NATIONAL ENERGY RESOURCES TRUST SERIES A, S-1/A, 1996-06-13

NATIONAL ENERGY RESOURCES TRUST SERIES A
S-1/A, 1996-06-13
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
As filed with The Securities and Exchange Commission on June 13, 1996.
REGISTRATION NO. 33-98042
================================================================================

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

AMENDMENT NO. 1
TO FORM S-1
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933

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

NATIONAL ENERGY RESOURCES TRUST SERIES
A THROUGH L
(Exact Name of Registrant as Specified in its Charter)

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

<TABLE>
<S> <C> <C>
CALIFORNIA 1300 APPLIED FOR
(State of Incorporation (Primary Standard Industrial (I.R.S. Employer
or Organization) Classification Code No.) Identification No.)
21800 BURBANK BLVD, SUITE 100
WOODLAND HILLS, CALIFORNIA 91364
(800) 201-8666
(Name, address, including zip code and telephone number,
including area code, of Registrant's principal executive office)
</TABLE>

<TABLE>
<S> <C>
MARSHALL J. FIELD WITH COPIES TO:
President MARK A. ROBERTSON, ESQ.
NATIONAL ENERGY RESOURCES, INC. ROBERTSON & WILLIAMS
21800 BURBANK BLVD., SUITE 100 3033 N.W. 63RD ST., SUITE 160
WOODLAND HILLS, CALIFORNIA 91364 OKLAHOMA CITY, OK 73116
(800) 201-8666 (405) 848-1944
(Name, address, including zip code and telephone number,
including area code, of agent for service)
</TABLE>

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

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
As soon as possible after the Effective Date of the Registration Statement.

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

If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to Rule 415 under the
Securities Act of 1933, check the following box. [x]

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE
OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SECTION 8(A), MAY
DETERMINE.
================================================================================
<PAGE> 2
NATIONAL ENERGY RESOURCES TRUST SERIES
A THROUGH L

CROSS REFERENCE SHEET
SHOWING LOCATION IN PROSPECTUS,
FILED AS PART OF REGISTRATION STATEMENT, OF
INFORMATION REQUIRED BY FORM S-1
<TABLE>
<CAPTION>
ITEM
NUMBER IN
FORM S-1 ITEM CAPTION IN FORM S-1 LOCATION IN PROSPECTUS
- -------- ------------------------ ----------------------
<S> <C> <C>
1. Forepart of Registration Statement and Outside
Front Cover Page of Prospectus . . . . . . . . . . . Front Cover Page

2. Inside Front and Outside Back
Cover Pages of Prospectus . . . . . . . . . . . . . . Back Cover Page

3. Summary Information, Risk Factors and Ratio of
Earnings to Fixed Changes . . . . . . . . . . . . . . Summary of Prospectus; Risk
Factors

4. Use of Proceeds . . . . . . . . . . . . . . . . . . . . Use of Proceeds

5. Determination of Offering Price . . . . . . . . . . . . Front Cover Page

6. Dilution . . . . . . . . . . . . . . . . . . . . . . . Not Applicable

7. Selling Security Holders . . . . . . . . . . . . . . . Not Applicable

8. Plan of Distribution . . . . . . . . . . . . . . . . . Front Cover Page; Plan of
Distribution

9. Description of the Securities . . . . . . . . . . . . Summary of Prospectus;
Description of Trust Units

10. Interest of Named Experts and Counsel . . . . . . . . . Not Applicable

11. Information with Respect to Registrant . . . . . . . . The Trust; National Energy;
The Production Payment and
Underlying Properties

12. Disclosure of Commission Position on
Indemnification for Securities Act
Liabilities . . . . . . . . . . . . . . . . . . . . . National Energy

13. Expenses of Issuance and
Distribution . . . . . . . . . . . . . . . . . . . . Part II of Registration Statement

14. Indemnification of Directors and Officers . . . . . . . Part II of Registration Statement

15. Recent Sales of Unregistered Securities . . . . . . . . Part II of Registration Statement

16. Exhibits; Financial Statement Schedules . . . . . . . . Exhibits to Registration Statement

17. Undertakings . . . . . . . . . . . . . . . . . . . . . Part II of Registration Statement
</TABLE>
<PAGE> 3
PROSPECTUS

NATIONAL ENERGY RESOURCES TRUST SERIES
6,000 TRUST UNITS

Each unit of beneficial interest ("Trust Unit") offered by National
Energy Resources, Inc. ("National Energy") the sponsor of the Trusts, evidences
an undivided interest in the National Energy Resources Trusts ("Trusts"), a
series of grantor trusts to be formed for the purpose of acquiring oil and gas
production payments. The assets of each Trust will consist of defined
production payments ("Production Payments") from working interests in producing
properties located in Texas, Oklahoma, Louisiana and Mississippi (collectively,
the "Underlying Properties"). The Trusts will receive the proceeds of the
offering.

This Prospectus describes the 500 Trust Units offered in National
Energy Resources Trust-A ("Trust-A") on an all-or-none basis. The Production
Payment to be purchased by Trust-A will entitle the Trust to receive 78% of the
Net Cash Flow from the Underlying Properties until the Trust has received
$500,000 plus an amount equal to 12 1/2% per annum of the principal sum.
Additional Trust Units may be offered in Trust B through L only upon the
closing of this offering, up to a total of 6,000 Trust Units for the entire
Series A though L. Each offering including the offering in Trust A, will be
for a period of 3 months from the date of its Prospectus, which period may be
extended by National Energy for 60 days (the "Offering Period"). Units in only
one Trust will be offered at a time. Each Trust will include a minimum of 500
Trust Units and may include a maximum number of Trust Units if the identified
underlying properties permit a larger Production Payment. Except for the 500
Trust Units to be issued by Trust-A, no Trust Units are offered by this
Prospectus unless it is accompanied by a Supplemental Prospectus relating to
the Trust for which Trust Units are then being sold. There is no assurance
that any additional Trust Units will be offered after the 500 Trust Units for
Trust-A.

Each Trust will be terminated (i) when investors have received from
the Production Payment their original investment plus interest at a rate per
annum specified for that trust anticipated to occur 5 years from the date of
formation of the Trusts; (ii) upon sale of the Production Payment which may
occur at any time after 2 years from the date of formation of the Trusts by
exercise of the Option by National Energy or a vote of 80% of the Trust
Unitholders; (iii) upon expiration of the number of years specified to comply
with the rule against perpetuities; or (iv) by vote of 80% of the Trust
Unitholders.

1. INVESTMENT IN THE SECURITIES IS SPECULATIVE AND INVOLVES A HIGH DEGREE
OF RISK.

2. SEE "RISK FACTORS" AT PAGE 10 FOR INFORMATION THAT SHOULD BE
CONSIDERED BY EACH PROSPECTIVE INVESTOR.

3. THERE IS NO PUBLIC MARKET FOR THE TRUST UNITS.

4. ASSETS OF THE TRUSTS WILL BE LIMITED TO THE PRODUCTION PAYMENT
DESCRIBED IN THE PROSPECTUS FOR EACH TRUST.

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
==========================================================================================================
Initial Public Underwriting Proceeds to
Offering Price Commission (1) Trust (2)(3)
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Trust Unit . . . . . . . $1,000.00 $80.00 $920.00
------------------------------------------------------------------------
Total Trust-A . . . . . . $500,000.00 $40,000.00 $460,000.00
Total Series . . . . . . $6,000,000.00 $480,000.00 $5,520,000.00
==========================================================================================================
</TABLE>

(See Footnotes on the following page)

The date of this Prospectus is ____________, 1996.

<PAGE> 4
(1) There is no firm commitment underwriting. The Trust Units are being
offered on a best efforts basis by members of the National Association
of Securities Dealers, Inc. (the "Soliciting Dealers"). National
Energy Resources, Inc. ("Sponsor") has agreed to indemnify the
Soliciting Dealers against certain liabilities including liabilities
under the Securities Act of 1933, as amended. See "PLAN OF
DISTRIBUTION."

(2) All subscriptions will be payable to Boatmen's Trust Company ("Escrow
Agent") and will be held along with the Subscription Agreements in
escrow by the Escrow Agent until the offering is closed or terminated.
Subscription funds will earn interest during the escrow which will be
paid to the subscribers promptly after the closing or termination of
the offering. Subscription funds will be returned promptly to
subscribers by the Escrow Agent if an offering fails to raise $500,000
within the Offering Period. Subscription Agreements may be revoked by
subscribers until they are counter signed by National Energy which has
15 days after receipt of the Subscription Agreements by the Escrow
Agent to accept them.

(3) Before deducting expenses of the offering payable by Trust estimated
at $30,000 for the Trust-A and $360,000 for the entire Series.

_____________________

AVAILABLE INFORMATION

National Energy Resources Trust Series has filed with the Securities
and Exchange Commission, Washington, D.C. ("SEC"), a registration statement on
Form S-1, Registration No. 33-98042 ("Registration Statement), under the
Securities Act of 1933, as amended ("Securities Act"), with respect to the
Trust Units offered hereby. This prospectus (together with any supplement)
which is a part of the Registration Statement ("Prospectus"), omits certain of
the information contained in the Registration Statement in accordance with the
rules and regulations of the SEC, and reference is hereby made to the
Registration Statement and the exhibits thereto for further information with
respect to the Trusts and the Trust Units. Statements made in this Prospectus
concerning the provisions of any document are not necessarily complete and, in
each instance, reference is made hereby to the copy of such document filed as
an exhibit to the Registration Statement. Each such statement is qualified in
its entirety by such references. Items of information omitted from this
Prospectus but contained in the Registration Statement may be inspected and
copies at the public reference facilities maintained by the SEC at 450 Fifth
Street, N.W., Washington, D.C. 20549; Everett McKinley Dirksen Building, 219
South Dearborn Street, Room 1204, Chicago, Illinois 60604; and 75 Park Place,
Room 1228, New York, New York 10007, at prescribed rates.

This Prospectus does not constitute an offer to sell or the
solicitation of an offer to buy the Trust Units offered hereby in jurisdictions
in which such offer or solicitation is unlawful.

<TABLE>
<S> <C>
PROSPECTUS SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
THE TRUST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
THE PRODUCTION PAYMENT AND THE UNDERLYING PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
NATIONAL ENERGY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
FEDERAL INCOME TAX CONSEQUENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
ERISA CONSIDERATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
DESCRIPTION OF THE TRUST AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
DESCRIPTION OF THE TRUST UNITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
VALIDITY OF SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
EXPERTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
INDEX TO FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

RESERVE REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exhibit A
</TABLE>

2
<PAGE> 5
PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more
detailed information appearing elsewhere in this Prospectus. See "Risk
Factors" for considerations relevant to an investment in the Trust Units.

THE OFFERING

<TABLE>
<S> <C>
Trust Units offered . . . . . . . . . . . . A total of 6,000 Trust Units is being offered of which only 500 to be
issued by Trust-A are being offered by means of this Prospectus. The
additional Trust Units will be offered only by this Prospectus when
accompanied by a Supplemental Prospectus relating to the Trust in
which Trust Units are then being offered.

Purchase Price . . . . . . . . . . . . . . $1,000 per Trust Unit with a minimum of Ten (10) Trust Units ($10,000)
per investor and a minimum of 500 ($500,000) total Trust Units per
Trust. Trust A will consist of 500 Trust Units. Trusts offered later
may include additional Trust Units.

Production Payment . . . . . . . . . . . . For Trust A, the Production Payment will be equal to 78% of the Net
Cash Flow from the Underlying Properties consisting of 5 producing
natural gas wells in Oklahoma until Trust A receives $500,000 plus 12
1/2% per annum. For the other Trusts the percentage of Net Cash Flow
will vary depending on the estimated future net revenues of the wells
selected and the interest rate may vary from 12 to 14%.

Use of Proceeds . . . . . . . . . . . . . . 8% commission payable to the selling broker dealer; up to 6% as a
reimbursement of offering expenses to National Energy; 86% to the
Trust for the purchase of the Production Payment from National Energy.

Sponsor . . . . . . . . . . . . . . . . . National Energy Resources, Inc.
21800 Burbank Blvd., Suite 100
Woodland Hills, California 91364
(800) 201-8666

Trustee . . . . . . . . . . . . . . . . . Boatmen's Trust Company, an Oklahoma trust company

Cash Distributions . . . . . . . . . . . . Semi-annual distributions will be made to Trust Unitholders in an
amount equal to 12 1/2% per annum on the amount of their investment.
The excess of receipts from the Production Payment over the
distribution will be used to establish a Reserve Fund to pay the
amount of Unitholder's investment upon the termination of the Trust.

Trust Term . . . . . . . . . . . . . . . . The Trust will terminate when the Production Payment is paid in full
which is expected to occur in 5 years. The Trust will also terminate
if National Energy exercises its option to repurchase the Production
Payment which is may occur at any time after 2 years from the
effective date of
</TABLE>

3
<PAGE> 6

<TABLE>
<S> <C>
the Production Payment. Otherwise the Trust will terminate upon vote
of 80% of the Unitholders or the lapse of years specified in the Trust
Agreement to avoid violation of the rule against perpetuities.

Redemption of
Trust Units . . . . . . . . . . . . . . . No Trust Units will be redeemed except in connection with the
termination of the Trust when all Trust Units will receive
distributions in complete payment of Unitholders initial investment
(or partial payment if cash proceeds of Trust Assets are insufficient
to make full payment).
</TABLE>

NATIONAL ENERGY RESOURCES TRUST SERIES

National Energy Resources, Inc. ("National Energy") is the sponsor of a
series of trusts offering up to 6,000 units of beneficial interests ("Trust
Units"). Certificates evidencing the Trust Units will be issued on the Closing
Date of each trust. Each trust will offer a minimum of 500 Trust Units for a
possible total of 12 grantor trusts to be formed during the 12 month period
following the effective date of registration of the Trust Units.

Each trust will be a grantor trust formed pursuant to a Trust Agreement
in substantially the form of agreement included in the Registration Statement
filed with the SEC. Boatmen's Trust Company will serve as the trustee of each
trust and subscribers to Trust Units will be the grantors and the beneficiaries
of the trusts. The name of the trusts will be National Energy Resources Trust
plus the designation of a letter from A through L to indicate the specific
trust. Subscribers to the first 500 Trust Units will be grantors and
beneficiaries of National Energy Resources Trust-A ("Trust-A"), subscribers to
the second 500 Trust Units will be grantors and beneficiaries of National
Energy Resources Trust B and so forth unless in the discretion of National
Energy a trust should be formed with more than the minimum 500 Trust Units. In
no event will a trust be formed with less than 500 Trust Units. The term
"Trust" as used hereafter shall refer to all the trusts together or to a single
trust as the context may require.

This Prospectus describes only the Underlying Properties and Production
Payment which will be included in the first trust to be formed after the
commencement of this offering. Thereafter a Supplemental Prospectus will
describe the Underlying Properties and Production Payment to be included in the
Trust to be formed on the closing of the next group of Trust Units sold.
Except for the 500 Trust Units to be issued by Trust-A, no Trust Units are
offered by this Prospectus unless it is accompanied by a Supplemental
Prospectus relating to the Trust for which Trust Units are then being sold.
There is no assurance that any additional Trust Units will be offered after the
500 Trust Units for Trust- A.

The Trust will be a passive entity and will not engage in business.
The Trustee will have only such powers as are necessary for the collection and
distribution of the proceeds received by the fund, the establishment,
maintenance and final distribution of a Reserve Fund and the payment of Trust
liabilities and expenses.

TRUST ASSETS

After the completion of the offering for each Trust, the Trust will
purchase from National Energy a production payment from a group of oil and gas
properties (the "Underlying Properties") which will entitle the Trust to
receive a specified percentage of net cash flow from the Underlying Properties
until the Trust has received a sum of money equal to the total contributions of
Trust Unitholders (at least $500,000 for each trust) plus a specified annual
rate of return which is expected to range from 12% to 14%. The exact rate of
return, the specific terms of the Production Payment, a description of the
Underlying Properties from

4
<PAGE> 7
which a Production Payment is carved and an estimate of the reserves
attributable to the Underlying Properties as well as to the Production Payment
as they relate to a particular Trust will be described in a Supplement to this
Prospectus except as to Trust-A which is described below.

The Production Payment owned by the Trust and the Reserve Fund
established by the Trustee out of part of the receipts of the Production
Payment will be the sole assets of a Trust. The Underlying Properties from
which a Production Payment is carved will be completely separate from the
Underlying Properties burdened by a Production Payment payable to another
Trust.

PRODUCTION PAYMENT. A production payment is a right to a specified
share of the production from minerals in place or the proceeds from production
which has an expected economic life at the time of its creation of shorter
duration than the economic life of one or more of the mineral properties
burdened by the payment. The share of production may be limited in time by
dollar amount or amount of production. The Production Payment owned by a Trust
will be limited by the dollar amount of the total contributions ($500,000 or
more) to the Trust by its grantors (the subscribers to Trust Units) plus a
specified percentage (from 12% to 14%) per annum of the total contributions.
The Production Payment will be payable by National Energy out of a specified
percentage of the net cash flow from the Underlying Properties. "Net Cash
Flow" is defined in the Conveyance of Production Payment as the total revenues
received from the sale of production less all costs and expenses, including
gross production taxes, lease operating expenses, workover costs, development
costs, and any other expenses directly attributable to ownership of the working
interest in the Underlying Properties other than Federal and state income tax.
National Energy expects to acquire only those Underlying Properties which have
estimated reserves sufficient to create a Production Payment which will reach
its term in 5 years or less, but there can be no assurances that any Production
Payment will be paid in full in the expected time period or any time period.
See "Risk Factors."

Under the terms of the Conveyance of Production Payment, National
Energy will have the right to repurchase the Production Payment at any time
after 2 years from the Effective Date at a purchase price equal to an amount
sufficient to pay the amount of the total contributions of the Trust
Unitholders plus the specified annual rate of return for that Trust, less
amounts already distributed to the Unitholders and the amount held in the
Reserve Fund. In this event, the Trustee would distribute the cash to the
Trust Unitholders and terminate the Trust.

UNDERLYING PROPERTIES. National Energy will acquire working interests
in a group of oil and gas leases on which are located producing oil and gas
wells from Blackjack Oil & Gas, Inc. ("Blackjack") an Oklahoma corporation
which is not affiliated with National Energy or the Trust, or from other
independent oil and gas operators. Blackjack owns, operates and acquires oil
and gas properties located principally in Oklahoma, Texas, Louisiana and
Mississippi. A "working interest" is an interest in an oil and gas leasehold
which is subject to some portion of the cost of development, operation, or
maintenance. Although National Energy will be responsible for development
costs, and such costs would be deducted in calculating Net Cash Flow out of
which the Production Payment is paid, National Energy will not acquire working
interests in Underlying Properties where additional wells are expected to be
drilled. There will be, however, some workover costs associated with the wells
to be acquired, which will be paid by National Energy and deducted from gross
revenues in calculating Net Cash Flow. National Energy will own the Underlying
Properties subject to and burdened by the Production Payment, and is entitled
to any Net Cash Flow received by reason of such ownership in excess of the
percentage of Net Cash Flow paid to the Trust in satisfaction of the Production
Payment.

RESERVE FUND. The Production Payment owned by a Trust will entitle
the Trust to receive a specified percentage of the Net Cash Flow from the
Underlying Properties until the Trust has received the total investment in the
Trust made by Trust Unitholders plus a specified rate of return (from 12% to
14% per annum). Therefore, a portion of each payment received by the Trust
represents a return of capital. That part of the Production Payment which
represents a return of capital will be set aside in a separate interest bearing
account as a sinking fund (the "Reserve Fund"). Upon the full payment of the
Production Payment,

5
<PAGE> 8
the Trust will terminate and amounts in the Reserve Fund will be distributed to
Trust Unitholders as a return of their investment. The Trustee will manage the
Reserve Fund and will make all investment decisions with regard to the funds;
however, National Energy has the right to make recommendations to the Trustee
concerning investments of the Reserve Fund. Interest received on the Reserve
Fund will be used to pay general and administrative expenses of the Trust and
the Trustee's fees. Interest in excess of Trust expenses will reduce the
amount owed under the Production Payment and will be distributed to Trust
Unitholders upon termination of the Trust.

NATIONAL ENERGY RESOURCES TRUST-A

The Production Payment which will be purchased by Trust-A will entitle
the Trust to receive 78% of the Net Cash Flow from the Underlying Properties
until the Trust has received $500,000 plus an amount equal to 12 1/2% per annum
of the principal sum. The Underlying Properties to which this Production
Payment will be attributable are five (5) producing gas wells which have
well-established production histories and are operated by Blackjack. They are
located in the following named counties in Oklahoma and National Energy will
acquire the interests set forth below:

Action #2 in Logan County, Oklahoma. National Energy will acquire a
100% working interest burdened by a 23% royalty and overriding royalty
interest resulting in a 77% net revenue interest. Gas is being
purchased by Conoco, Inc.

Bryan #1-6 in Pawnee County, Oklahoma. National Energy will acquire a
100% working interest burdened by a 23% royalty and overriding royalty
interest resulting in a 77% net revenue interest. Gas is being
purchased by Conoco, Inc.

Davis #1-A in Oklahoma County, Oklahoma. National Energy will acquire
a 75% working interest burdened by a 28% royalty and overriding royalty
interest resulting in a 47% net revenue interest. Gas is being
purchased by GPM.

Enoch #1 in Blaine County, Oklahoma. National Energy will acquire a
100% working interest burdened by a 23% royalty and overriding royalty
interest resulting in a 77% net revenue interest. Gas is being
purchased by Trident NGL.

Phillips #1 in Ellis County, Oklahoma. National Energy will acquire a
100% working interest burdened by a 21% royalty and overriding royalty
interest resulting in a 79% net revenue interest. Gas is being
purchased by Midland Marketing Corp.

SUMMARY RESERVE INFORMATION. The following table sets forth, as of
April 17, 1996, the estimated proved producing oil and gas reserves, prices
used to estimate future net revenues, estimated future net revenues and
discounted estimated future net revenues attributable to the Underlying
Properties. The reserve report dated April 17, 1996, from which the following
information is derived was prepared by F. W. Elton, Petroleum Engineer, and is
attached to this Prospectus as Exhibit "A."

6
<PAGE> 9

<TABLE>
<CAPTION>
Reserve to Proved Proved Nat- Discounted
Name Production Producing Producing ural Estimated Estimated
of Index Reserves Reserves Oil Gas Future Net Future Net
Well (Years) Oil (Bbls) Gas (Mcf) Price Price Revenues Revenues*
<S> <C> <C> <C> <C> <C> <C> <C>
Bryan #1-6 15 0 1,165,226 -- .70 $ 475,496 $ 283,445
Enoch #1 10 0 226,590 -- 1.60 184,953 131,045

Action #2 11 0 370,295 -- 1.60 357,836 188,620

Davis #1 12 12,391 226,422 17.00 1.60 220,976 144,348
Phillips #1 13 0 242,406 -- 1.60 193,456 127,086

TOTALS 12,391 2,430,932 $1,432,717 $ 874,544

</TABLE>

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

*The Discount rate of 10% was used.

NET CASH FLOW. The following table sets forth the Net Cash Flow
allocable to Trust-A and to National Energy based on the Estimated Future Net
Revenues set forth in the Summary Reserve Table above. There are no assurances
that Trust Unitholders will receive the total cash distributions set forth
below due to fluctuations in oil and gas prices, seasonal demand for natural
gas, natural production declines and other risk factors inherent in any
investment in oil and gas. See "Risk Factors."

<TABLE>
<CAPTION>
Net Cash Allocation of
Flow Net Cash Flow to Trust Revenues Cash
Year to Trust National Energy Reserve Fund Distributions
<S> <C> <C> <C> <C>
1st $220,240 $ 22,740 $135,000 $ 62,500

2nd 204,235 16,735 125,000 62,500

3rd 176,177 8,677 105,000 62,500

4th 154,494 11,994 80,000 62,500

5th 137,106 19,606 55,000 62,500

TOTALS $892,252 $ 79,752 $500,000 $312,500
</TABLE>

NATIONAL ENERGY

National Energy Resources, Inc. is a California corporation formed in
August, 1994 for the purpose of engaging in the development and ownership of
oil and gas and for forming the Trusts and conducting this offering. Its
shareholder is Marshall J. Field who owns 100% of the issued and outstanding
stock of National Energy. Its only officer is Marshall J. Field. National
Energy was formed with minimum capital and its initial capital has been
substantially used in the up front costs of the offering for which it will be
reimbursed out of the proceeds of sale of Trust Units. The principal executive
offices of National Energy are located at 21800 Burbank Blvd., Suite 100,
Woodland Hills, California 91364 and its telephone number is (800) 201-8666.
See "National Energy."

National Energy has no prior experience in the oil and gas industry nor
does it have prior experience in sponsoring oil and gas investments such as the
Trust Units.

7
<PAGE> 10

SUMMARY OF RISK FACTORS

An investment in the Units is subject to certain risk factors that
should be evaluated by prospective investors before purchasing the Units. Such
risk factors include:

Risks associated with the oil and gas industry generally, including:

(a) decreased revenues and reduced production due to volatility of
oil and natural gas prices;

(b) increased production expenses which could result in reduced oil
or gas production volumes;

(c) reduced value of the Units if the reserve estimates of
quantities and values of natural gas differ materially from
actual quantities and values of reserves;

(d) risks of reduced distributions to Unitholders if production
were interrupted for any reason;

(e) entities not controlled by National Energy could curtail
production on the Underlying Properties or excess production
capacity could reduce natural gas prices, either of which could
adversely affect the Trust distributions;

(f) the amount of cash distributions throughout the year may vary
substantially due to the seasonal nature of demand;

(g) decisions regarding operations, future development and
production levels are made by an independent entity and such
decisions may result in decreased cash distributions; and

(h) the operator of the Underlying Properties has no contractual or
fiduciary duty to protect the interests of the Unitholders.

Risks associated with the Trust and the Trust Units in particular,
include:

(a) Trustee is not personally liable to Unitholders under terms of
Trust Agreement unless it acts in bad faith;

(b) Transfer of Underlying Properties in violation of Conveyance
could result in delay of distribution;

(d) Trust Unitholders have limited voting rights.

(e) No secondary market for Trust Units and illiquid investment;
and

(f) Trust Unitholders will not participate in revenues in excess of
Production Payment.

8
<PAGE> 11
SUMMARY FEDERAL INCOME TAX CONSEQUENCES

THE TAX CONSEQUENCES OF AN INVESTMENT IN TRUST UNITS TO A PARTICULAR
INVESTOR WILL DEPEND IN PART ON THE INVESTOR'S OWN TAX CIRCUMSTANCES. EACH
PROSPECTIVE INVESTOR SHOULD THEREFORE CONSULT HIS OWN TAX ADVISOR ABOUT THE
FEDERAL, STATE AND LOCAL TAX CONSEQUENCES TO SUCH INVESTOR IN TRUST UNITS.

The following is a summary of certain Federal income tax consequences of
acquiring, owning and disposing of Trust Units and is based on the opinion of
Robertson & Williams, counsel to National Energy Resources, Inc. ("Counsel").
For a more detailed discussion of these consequences and the qualifications to
and limitations of the opinions of Counsel, see "Federal Income Tax
Consequences" and "Risk Factors -- Tax Considerations."

<TABLE>

<S> <C>
Classification and Taxation
of the Trust . . . . . . . . . . . The Trust will be treated as a grantor trust and not as an association
taxable as a corporation. As a grantor trust, the Trust will not be
subject to tax. If the Trust were treated as an association taxable
as a corporation, it would be treated as a separate entity subject to
corporate tax on its taxable income.

Taxation of Holders . . . . . . . . . . . . Because the Trust will be treated as a grantor trust for Federal
income tax purposes, and because a Trust Unitholder will be treated,
for Federal income tax purposes, as directly owning an interest in the
assets of the Trust, each Trust Unitholder will be taxed directly on
his pro rata share of income attributable to the assets of the Trust
consistent with the Trust Unitholder's method of accounting and
without regard to the taxable year or accounting method employed by
the Trust.

Interest Income . . . . . . . . . . . . . . For Federal income tax purposes, the Production Payment will be
treated as a debt obligation. As a result, each purchaser of a Trust
Unit will be required to treat that portion of each payment received
by the Trust and distributed monthly to Trust Unitholders as interest
income.

Holder Reporting Information . . . . . . . Year-end tax information will be furnished to Trust Unitholders no
later than March 31 of the following year.
</TABLE>

9
<PAGE> 12
RISK FACTORS

An investment in the Trust is speculative and involves a high degree
of risk. Prior to making an investment, prospective investors should carefully
consider the following risk factors inherent in and affecting the business of
the Trust and this offering.

RISK ASSOCIATED WITH OIL AND GAS INDUSTRY GENERALLY

POTENTIAL DECREASE IN REVENUES DUE TO VOLATILITY OF OIL AND NATURAL
GAS PRICES AND PRODUCTION. The Trust's revenues will be dependent on the
prices received for oil and natural gas production from the Underlying
Properties and, in the case of Underlying Properties that are working
interests, the costs of producing and developing such oil and natural gas.
Prices for oil and natural gas are subject to wide fluctuations in response to
relatively minor changes in supply, market uncertainty and a variety of
additional factors that are beyond the control of the Trust and National
Energy. These factors include political conditions in the Middle East, the
foreign supply of oil and natural gas, the price of foreign imports, the level
of consumer product demand, the severity of weather conditions, government
regulations, the price and availability of alternative fuels and overall
economic conditions. In recent years, natural gas prices have been more
depressed than they have been historically when compared (on a net equivalent
barrel basis) to the price of oil. Although National Energy believes that in
the long-term prices for natural gas will increase in relation to oil prices,
no assurances can be made that natural gas prices will increase in relation to
oil prices or that the price of natural gas will increase at all.
Additionally, lower oil and natural gas prices may reduce the amount of oil and
natural gas that is economic to produce.

Oil and natural gas prices have historically been volatile and are
likely to continue to be volatile in the future. Such volatility makes it
difficult to estimate the future levels of cash distributions to Trust
Unitholders or the value of the Trust Units.

PRODUCTION EXPENSES - MAY AFFECT PRODUCTION AND REVENUES TO TRUST.
Production expenses typically include labor, fuel, repairs, hauling, pumping,
insurance, storage, and supervision and administration. Production expenses
may influence the decision of the operator as to the volume of oil or natural
gas to produce from a property or the decision to shut-in or abandon a well. A
working interest owner is obligated for its proportionate share of production
expenses. Accordingly, higher or lower production expenses on the Underlying
Properties may directly decrease or increase the amount received by the Trust
from the Production Payment. All of the Underlying Properties are in
productive fields where, based on information provided by Blackjack, material
increases in production expenses are currently not expected to occur in the
next several years.

REDUCED VALUE OF UNITS IF RESERVE ESTIMATES ARE INACCURATE. The value
of the Trust Units will be substantially dependent upon the proved producing
reserves attributable to the Production Payments owned by the Trust. There are
many uncertainties inherent in estimating quantities and value of proved
reserves and in projecting future rates of production. The reserve data set
forth herein, although prepared by independent consultants in a manner
customary in the industry, are estimates only, and quantities and estimated
values of oil and gas may differ from the amounts set fort herein. The Reserve
Report of F. W. Elton, Inc., appears as Exhibit "A." In
addition, the present values shown herein were prepared using guidelines
established for disclosure of reserves with the SEC and should not be
considered representative of the market value of such reserves or the Trust
Units. A market value determination would include many additional factors. As
of April, 1996, the estimated future net revenues from proved producing
reserves, attributable to the Production Payment, discounted at 10% per annum,
was $1,749 per Trust Unit.

DISTRIBUTION COULD BE AFFECTED IF PRODUCTION IS INTERRUPTED. Trust
distributions could be adversely affected if any of the hazards typically
associated with the production and transportation of oil and natural gas were
to occur, including personal injuries, property damage, damage to productive
formations or equipment and environmental damages. Uninsured costs for damages
for any of the foregoing will directly reduce the Production Payments from the
Underlying Properties to the extent such damages reduce the volume of oil and
natural gas produced.

10
<PAGE> 13

PRODUCTION COULD BE VOLUNTARILY CURTAILED, REDUCING TRUST
DISTRIBUTION. Approximately 97% of the estimated proved reserves of the
Underlying Properties at April, 1996, are comprised of natural gas, based on
the discounted present value of estimated future net revenues of proved
reserves. The revenues of the Trust and the amount of cash distributions made
by the Trust will be dependent upon, among other things, the volume of nature
gas produced and the price at which such natural gas is sold. Since the early
1980's, the available natural gas production capacity nationwide has exceeded
the demand by users of such gas, resulting in demand-related production
curtailments. In addition, existing gathering systems and pipelines
transporting natural gas to the users of such gas may not have sufficient
capacity to transport the entire allowable production from a field, resulting
in production from the Underlying Properties being curtailed. Curtailment may
exist for demand-related reasons. See "The Production Payments and the
Underlying Properties."

In addition, during the 1980's and early 1990's, excess natural gas
production capacity in the United States has generally resulted in downward
pressure on natural gas prices. The effect of any excess production capacity
which exists in the future cannot be predicted with certainty; however, any
such excess capacity may have a material adverse effect on Trust distributions
through its impact on prices and volumes.

SEASONAL DEMAND MAY CAUSE DISTRIBUTION TO VARY SUBSTANTIALLY. Due to
the seasonal nature of demand for natural gas and its effect on sales prices
and production volumes, the cash distributions by the Trust may vary
substantially on a seasonal basis. Generally, natural gas production volumes
and prices tend to be higher during the first and fourth quarters of the
calendar year. Because of the lag between National Energy's receipt of
revenues related to the Underlying Properties and the dates on which
distributions are made to Trust Unitholders, however, the seasonality that
affects production and prices generally should be reflected in distributions by
the Trust in later periods.

NATIONAL ENERGY AND THE TRUST EXERCISE LIMITED CONTROL OF OPERATIONS
AND DEVELOPMENT OF THE UNDERLYING PROPERTIES. Under the terms of the
Production Payment, neither the Trustee nor the Trust Unitholders will be able
to influence or control the operations or future development of the Underlying
Properties. Additionally, National Energy, which is the owner of the
Underlying Properties, will not operate or be able to significantly influence
the operations or future development of such Underlying Properties. All such
operations will be controlled by persons unaffiliated with the Trustee and
National Energy.

The Underlying Properties include National Energy's working interests
in producing properties located in Oklahoma, as described in "The Production
Payment and Underlying Properties". Each of these properties has an operating
agreement whereby, if the requisite percentage of working interest holders
approve a development project, all such holders are required to pay their
proportionate share of development costs. The working interests owned by
National Energy may not constitute a sufficient interest in any property to
veto or control a development decision. Under the terms of the Conveyance
creating the Production Payment in these Underlying Properties, the Trust will
not be liable for any development costs, but the amount of such development
costs will be deducted when computing Net Cash Flow payable to the Trust from
such properties.

THE OPERATOR OF THE UNDERLYING PROPERTIES HAS NO DUTY TO PROTECT
INTERESTS OF UNITHOLDERS. Under the terms of the operating agreements relating
to the Underlying Properties, Blackjack owes a duty to National Energy and the
other working interest owners to conduct the operations on the Underlying
Properties in a good and workmanlike manner and in accordance with its best
judgment of what a prudent operator would do under the same or similar
circumstances. Blackjack has no contractual or fiduciary duty to protect the
interest of the Trust or the Unitholders.

RISKS ASSOCIATED WITH TRUST AND TRUST UNITS IN PARTICULAR

FIDUCIARY RESPONSIBILITY OF TRUSTEE. The Trustee is responsible to
the Trust Unitholders as a fiduciary and, as such, under Oklahoma law is
required to act in the best interests of the Trust Unitholders at all times and
to exercise the judgment and care in supervising and managing the Trust's
assets exercised by persons of ordinary prudence, discretion and intelligence.
The Trust Agreement ("Agreement") provides, however, that the Trustee will

11
<PAGE> 14
not be personally liable to the Trust Unitholders for the failure to exercise
such standard of judgment and care, unless such failure is the result of bad
faith.

Due to the passive nature of the Trust, the Trustee is not required to
make business decisions affecting the assets of the Trust. Therefore, the
Trustee's primary functions under the Agreement are anticipated to be
ministerial. Under certain circumstances, however, the Trustee may be required
to approve or disapprove an extraordinary transaction affecting the Trust and
Trust Unitholders. These transactions include a sale of the Production
Payment, termination of the Trust and amendment of the Agreement. The Trustee
is required to act in the best interests of Trust Unitholders in connection
with any future extraordinary transactions but is not required to retain an
unaffiliated person to represent the Trust Unitholders.

Under Oklahoma law, if the Trustee, in bad faith, were to fail to
collect amounts owed to the Trust or distribute cash held by the Trust for
distribution, or otherwise, in bad faith, take or omit to take any action that
is in the best interest of the Trust Unitholders, the Trustee would be liable
to the Trust Unitholders for damages caused by any such act or omission,
including any loss or depreciation in value of the Trust assets or failure to
make a profit from such assets caused by such act or omission. Oklahoma law
permits the Trust Unitholders to file an action seeking other remedies for such
acts or omissions in addition to damages, including removal of the Trustee,
specific performance, appointment of a receiver, an accounting by the Trustee
to the Trust Unitholders, exemplary damages and other remedies. The
availability of these remedies provided by Oklahoma law is explicitly
incorporated into the Agreement.

TRANSFER OF UNDERLYING PROPERTIES IN VIOLATION OF CONVEYANCE COULD
RESULT IN DELAYED DISTRIBUTION. National Energy currently owns or has under
contract to purchase the Underlying Properties from which will be conveyed the
Production Payment to Trust-A. Under the terms of the Conveyance, National
Energy will have no right to transfer all or any portion of its working,
royalty, overriding royalty or fee mineral interests comprising the Underlying
Properties as long as they are burdened by the Production Payment without the
consent of the Trustee. The Production Payment constitutes a real property
interest. The Conveyances will be recorded in the appropriate real property
records so as to give notice of the Production Payments to National Energy's
creditors and transferees, whose rights would be subject to the Production
Payments and whose interests would be subsequent and inferior to the Production
Payments. Any transferee will succeed to the responsibilities of National
Energy as to the interests so transferred, including the payment duties and
corresponding liabilities to the Trust for damages caused by breach of such
responsibilities. The Agreement does not provide a specific mechanism whereby
Trust Unitholders may compel the Trustee to institute action against National
Energy or a transferee of an Underlying Property for damages caused by a delay
or reduction in the payment of Production Payments to the Trust. As discussed
under "-- Fiduciary Responsibility of Trustee," above, if the Trustee were to
refuse in bad faith to enforce such damage remedies, the Trustee would be
liable to the Trust Unitholders.

The Trustee may cause the sale of the Production Payments if the
holders of 80% or more of the Trust Units approve such sale or if National
Energy exercises its option to purchase the Production Payment after two years.
The net proceeds of any sale will be distributed to the Trust Unitholders and
the Trust would be terminated. See "Description of the Trust Agreement --
Duration of the Trust; Sale of Production Payments."

ABANDONMENT OF A WELL WILL EXTINGUISH PORTION OF PRODUCTION PAYMENT.
National Energy and any transferees will have the right to abandon any well or
property on an Underlying Property that is a working interest if, in its
opinion, such well or property ceases to produce or is not capable of producing
in commercially paying quantities, and upon termination of any such lease, that
portion of the Production Payments relating thereto will be extinguished.

The Underlying Properties are currently operated by Blackjack and
National Energy does not anticipate any change in operations. The current
operator of the Underlying Properties is under no obligation to continue
operating the properties, and the Trustee, Trust Unitholders and National
Energy may be unable to appoint or control the appointment of a replacement
operator. See "Production Payments and the Underlying Properties --
Description of the Underlying Properties."

12
<PAGE> 15
LIMITED VOTING RIGHTS OF TRUST UNITHOLDERS. While Trust Unitholders
will have certain voting rights pursuant to the terms of the Trust Agreement,
these rights are more limited than those of stockholders of most public
corporations. For example, there is no requirement for annual meetings of
Trust Unitholders or for an annual or other periodic re-election of the
Trustee. See "Description of the Trust Units -- Voting Rights of Trust
Unitholders."

TAX CONSIDERATIONS. The Trust has received an opinion of Counsel that
the Trust is a "grantor trust" for Federal income tax purposes, and that each
Trust Unitholder will be taxed directly on his pro rata share of the income of
the Trust and his pro rata share of other deductions of the Trust. Counsel
believes that its opinion is in accordance with the present position of the IRS
regarding these tax questions. There can be no assurances that National Energy
or the Trust would be granted such a ruling if requested or that the IRS will
not change it position in the future. The tax treatment of the Trust and Trust
Unitholders could be materially different from that described above if the IRS
were to successfully challenge that treatment. See "Federal Income Tax
Consequences."

LACK OF SECONDARY MARKET AND ILLIQUID INVESTMENT. There is no
secondary market for the Trust Units and none is anticipated. Trust
Unitholders will therefore, not be able to liquidate their investment readily
and should expect to hold the Trust Units for the duration of the Trust.

TRUST UNITHOLDERS WILL NOT PARTICIPATE IN EXCESS REVENUES. The Trust
will receive from the Production Payment only the amounts specified in the
Conveyance which for Trust A is $500,000 plus 12 1/2% per annum. This amount
will be paid out of 78% of the Net Cash Flow from the sale of oil and gas
produced by the Underlying Properties (which may be a different percentage for
other Trusts) which is anticipated to be accomplished in 5 years based on the
reserve reports. If gas prices or production increase, the Trust will not
receive a larger total sum but the Production Payment will be paid in a shorter
time period. If gas prices or production decrease, the Production Payment will
be paid over a longer period and there is the risk that it will not be paid in
full.

USE OF PROCEEDS

The Trust will receive all the proceeds from the sale of the Trust
Units, all of which will be paid to National Energy for the Production Payment.
National Energy will apply the proceeds from the sale of Trust Units in Trust-A
in the approximate amounts set forth in the table below although there can be
no assurance that the actual amounts will not vary from those set forth below:

<TABLE>
<S> <C>
Commissions $ 40,000
Offering Expenses(1) 30,000
Acquisition of Production Payment 430,000
</TABLE>

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

(1) Includes legal and accounting fees, consulting fees, Federal and state
securities registration fees, escrow fees, printing and copying
charges, telephone expense and miscellaneous costs.

THE TRUST

Trust-A will be formed pursuant to the Trust Agreement between
Boatmen's Trust Company as trustee, and National Energy upon the deposit into
escrow of $500,000 in payment for 500 Trust Units.

National Energy currently owns or has under contract to purchase, the
Underlying Properties which will be subject to and burdened by the Production
Payment to be purchased by Trust-A from the proceeds of this offering.
Accordingly, National Energy, as owner of the Underlying Properties, will
receive payments from purchasers of production or the operators of such
properties. National Energy will aggregate these payments, deduct operating
costs and other expenses related to the Underlying Properties, and make payment
to the Trustee each month for the amounts due to Trust-A under the Production
Payment.

13
<PAGE> 16
FEES AND EXPENSES

The following is a description of certain fees and expenses
anticipated to be paid or borne by Trust-A, including all fees expected to be
paid to National Energy, the Trustee or their affiliates.

ORGANIZATIONAL AND OFFERING EXPENSE. The organization and offering
expenses allocable to Trust-A are $30,000 (6% of the subscription proceeds) for
legal and accounting fees, consulting and engineering fees, registration fees,
printing and miscellaneous costs, which will be reimbursed to National Energy
upon the close of the offering of Trust Units in Trust-A. Each subsequent
trust will bear the same percentage (6%) for organizational and offering
expenses. National Energy has borne and paid the expenses of the entire
offering of Units in the Trust Series but each trust will reimburse National
Energy only one-twelfth (1/12) of such expenses or if more than 500 Units are
offered by a Trust, that Trust will bear expenses in proportion to the number
of Units issued by it bears to the total number of Units included in the
registration.

INTEREST. National Energy will not pay interest on any amounts
received from the Underlying Properties prior to payment to Trust-A.

TRUST ADMINISTRATIVE EXPENSES. The Trustee will be paid a trustee fee
of $1,200 per year per trust and an escrow fee of $600 per account. See
"Description of the Trust Agreement -- Compensation of the Trustee." The Trust
will also incur legal, accounting and engineering fees, mailing and printing
costs and other expenses which will be reimbursed to the Trustee at cost.

THE PRODUCTION PAYMENT AND THE UNDERLYING PROPERTIES

GENERAL

The Production Payments will be carved out of the Underlying
Properties which will consist of working interests in producing oil and gas
properties acquired by National Energy from Blackjack or other independent oil
and gas operators. The Production Payment to be acquired by Trust-A will
entitle Trust-A to receive 78% of the Net Cash Flow from the sale of oil and
gas produced from the Underlying Properties until the Trust has received
generally the total investment made by its Trust Unitholders ("Primary Sum") as
adjusted for potential expenses, interest income on reserves and general and
administrative expenses, plus interest at the rate of 12 1/2% per annum on the
Primary Sum. The Primary Sum will be increased if the Trust should be
compelled for any reason to make payments on account of ownership of the
Production Payment and will be decreased by the amount of interest income on
the Reserve Account in excess of general and administrative expenses, if any.
The net effect of these adjustments is to maintain the Primary Sum at $500,000.
In general, Net Cash Flow equals the gross proceeds received by National Energy
from the sale of production less designated costs, including transportation and
marketing costs, applicable production and property taxes, operating and
development costs. The computation of the Production Payment and its repayment
is more specifically described in the Conveyance.

DESCRIPTION OF UNDERLYING PROPERTIES

Davis #1-A in Oklahoma County, Oklahoma. National Energy will acquire
a 75% working interest burdened by a 28% royalty and overriding
royalty interest resulting in a 47% net revenue interest. Gas is
being purchased by GPM.

14
<PAGE> 17

None of the royalty or overriding royalty interests burdening the above
described properties is owned by an affiliate of National Energy or the Trust.

RESERVES

The following table summarizes estimated proved producing reserves
attributable to the Production Payment and the Underlying Properties to be
included in Trust-A as of April, 1996 as set forth in the Reserve Report
attached as Exhibit "A."

<TABLE>
<CAPTION>
Production Payment Underlying Properties
------------------ ---------------------
Proved Producing
<S> <C> <C>
Oil (Bbls) 4,540 5,821
Gas (Mcf) 1,360,170 1,743,808

Future net revenues $812,500 $1,432,717

Present value discounted
at 10% per annum $682,144 $ 874,544
</TABLE>

The reserve estimates were prepared using assumptions required by the
Financial Accounting Standards Board. Such assumptions include the use of
period-end prices for oil and natural gas and period-end costs for estimated
future development and production expenditures to produce the proved reserves.
Future net cash flows are discounted at a 10% per annum rate. Because the
Trust and National Energy (as owner of the Underlying Properties) are not
subject to Federal income taxation, no provision is included for Federal income
taxes.

Proved reserve quantities are estimates based on information
available, including prices and costs, at the time of preparation. Such
estimates are by their very nature imprecise and subject to change as
additional information becomes available. The Reserve Report uses prices for
natural gas in effect at the time the reserve report was prepared. Such prices
are influenced by seasonal demand for natural gas and may not be the most
appropriate or representative prices to use in estimating future revenues or
reserve data. See " -- Oil and Gas Sales Prices," below for a description of
average gas prices received by the owner of the Underlying Properties. The
reserves actually recovered and the timing of production of those reserves may
be substantially different from the foregoing estimates. Moreover, the present
values shown above should not be considered representative of the market value
of such reserves. A market value determination would include many additional
factors.

Proved reserve quantities set forth in the foregoing table are
calculated in accordance with the SEC's guidelines for disclosure of oil and
natural gas reserves and assume that oil and natural gas prices, production
expenses and development costs in effect on the date of the report remain
constant over the economic life of the property. Proved reserve quantities for
the Underlying Properties are calculated by multiplying the net revenue
interest applicable to the Underlying Properties by the total amount of oil and
natural gas estimated to be economically recoverable from the properties.
Reserve quantities are calculated differently for the Production Payment
because such interests do not entitle the Trust to a specific quantity of oil
or gas. Proved reserves attributable to the Production Payment, which are
carved out of the Underlying Properties are calculated by deducting an amount
of oil or gas sufficient, if sold at the prices used in preparing the reserve
estimates for the Underlying Properties, to pay the Primary Sum, as adjusted
for interest earned, less general and administrative expenses, plus

15
<PAGE> 18
interest at an annual rate of 12-1/2% over a term of 5 years. As oil and
natural gas prices vary from those used to calculate the applicable reserve
estimate, more or less quantities of oil and natural gas are required to pay in
full the Production Payment.

The underlying properties were selected for their consistent
production history and for estimated future net revenues in the amounts
sufficient to return $500,000 plus 12.5% per annum in 5 years without depleting
reserves since it is a requirement for production payments that they be paid
solely out of reserves in a period less that the life of the properties as
estimated at the time the production payment is created. The Company has no
interest in any adjacent properties; however, the operator may. The trusts
would not be entitled to participate in any other wells in the area as the
Production Payment is limited to the wells identified. Oklahoma's spacing laws
would prevent the operator from drilling additional wells which would
jeopardize production from the Underlying Properties. If drainage occurs, the
trusts would have legal rights to damages.

AVERAGE PRICES ON UNDERLYING PROPERTIES

Year to year changes in oil prices relate directly to changes in
posted prices. The average wellhead price received in 1995 was $17.00 per
barrel. The posted price for crude oil in Oklahoma on June 6, 1996 was $18.50
per barrel.

Year to year changes in gas prices relate directly to changes in
posted prices. The average natural gas price for production from the five
wells included in the Underlying Properties during 1992 was $1.76 per Mcf. The
average natural gas price for production from these properties during 1993 was
$2.03 per Mcf, and was $1.70 per Mcf for 1994, and $1.42 per Mcf for 1995.

PRODUCTION HISTORY FOR UNDERLYING PROPERTIES

The Action #2 well was recompleted by Maze Oil & Gas in March 1993.
It is located in Logan County, Oklahoma. The initial production was
500 Mcf of gas per day and produces from the Hoover Zone. It has
produced for three years and has another eleven years of economic life.

The Bryan #1 well was drilled and completed by Blackjack Oil in 1994.
It is located in Pawnee County, Oklahoma. The initial production was
750 Mcf of gas per day and produces from the Tonkawa Sand. It has
produced for two years and has another fifteen years of economic life.

The Davis well was drilled by J.L. Thomas in 1953. It is located in
Oklahoma County, Oklahoma. The initial production was 1.7 Mmcf of gas
per day and produces from the Bartlesville Zone. It has produced for
thirty-three years and has another twelve years of economic life.

The Enoch well was drilled by Heffel Resources in 1989. It is located
in Blaine County, Oklahoma. The initial production was 275 Mcf of gas
per day and produces from the Morrow Zone. It has an economic life of
ten years.

The Phillips #1 well was drilled by Phillips Petroleum in 1962. It is
located in Ellis County, Oklahoma. The initial production was 1.8
Mmcf of gas per day and produces from the Morrow Zone. It has an
economic life of thirteen years.

COMPETITION, MARKETS AND REGULATIONS

COMPETITION. The oil and natural gas industry is highly competitive
in all of its phases. National Energy will encounter competition from major
oil and natural gas companies, independent oil and natural gas concerns, and
individual producers and operators. Many of these competitors have greater
financial and other resources than National Energy. Competition may also be
presented by alternative fuel sources, including heating oil and other fossil
fuels.

16
<PAGE> 19

MARKETS. Where the Underlying Properties consist of royalty or
royalty interests in properties, the operators of the properties will make all
decisions regarding the marketing and sales of oil and natural gas production.
Although National Energy generally has the right to market oil and natural gas
produced from the Underlying Properties that are working interests, National
Energy will generally rely on the operators of the properties to market the
production. The ability of the operators to market the oil and natural gas
from the Underlying Properties will depend upon numerous factors beyond their
control, including the extent of domestic production and imports of oil and
natural gas, the proximity of the natural gas production to gas pipelines, the
availability of capacity in such pipelines, the demand for oil and natural gas
by utilities and other end-users, the effects of inclement weather, state and
Federal regulation of oil and natural gas production and Federal regulation of
natural gas sold or transported in interstate commerce. There is no assurance
that such operators will be able to market all of the oil or natural gas
produced on the Underlying Properties or that favorable prices can be obtained
for the oil and natural gas produced.

The supply of natural gas capable of being produced in the United
States has exceeded demand in recent years as a result of decreased demand for
natural gas in response to economic factors, conservation, lower prices for
alternative energy sources and other factors. As a result of this excess
supply of natural gas, natural gas producers have experienced increased
competitive pressure and significantly lower prices. Many natural gas
pipelines have reduced their takes from producers below the amount they were
contractually obligated to take or pay at fixed prices in excess of spot prices
or have renegotiated their obligations to reflect more market responsive terms.
The decline in demand for natural gas resulted in many pipelines reducing or
ceasing altogether their purchases of new natural gas. Substantially all of
National Energy's natural gas production is sold at market responsive prices.

Demand for natural gas production has historically been seasonal in
nature. Due to unseasonably warm weather over the last several years the
demand for natural gas has decreased, resulting in lower prices received by
producers during the winter months than in prior years. Consequently, on an
energy equivalent basis, natural gas has sold at a discount to oil for the past
several years. Such price fluctuations will directly impact Trust
distributions, estimates of Trust reserves and estimated future net revenue
from Trust reserves.

In view of the many uncertainties affecting the supply and demand for
crude oil, natural gas and refined petroleum products, National Energy is
unable to make reliable predictions of future oil and natural gas prices and
demand or the overall effect they will have on the Trust. National Energy does
not believe that the loss of any of its purchasers would have a material
adverse effect on the Trust, since substantially all of the natural gas sales
from Underlying Properties are made on the spot market.

REGULATION

The production, transportation and sale of oil and gas from the
Underlying Properties are subject to Federal and state governmental regulation,
including regulations concerning the ceiling prices at which certain categories
natural gas may be sold, regulation of tariffs charged by pipelines, taxes, the
prevention of waste, the conservation of oil and natural gas, pollution
controls and various other matters. The United States has power to permit
increases in the amount of oil imported from other countries and to impose
pollution control measures.

FEDERAL REGULATION OF NATURAL GAS. The Underlying Properties will be
subject to the jurisdiction of the Federal Energy Regulatory Commission
("FERC") and the Department of Energy ("DOE") with respect to various aspects
of oil and natural gas operations including marketing and production of oil and
natural gas. The Natural Gas Act and the Natural Gas Policy Act of 1978
("Policy Act") mandate federal regulation of interstate transportation of
natural gas and of wellhead pricing of certain domestic natural gas, depending
on the category of the natural gas and the nature of the sale. In July 1989,
however, Congress enacted legislation that terminated wellhead price controls
on all domestic natural gas as of January 1, 1993, with price-decontrol
effective immediately for certain gas, and effective for other gas as contracts
expire or are terminated. Natural gas from newly spudded wells was
price-decontrolled on May 15, 1991. In addition, parties may voluntarily agree
in writing, as of July 26, 1989 and thereafter, to effect decontrol of natural
gas.

In April 1992, the FERC issued Order No. 636, which provides for the
fundamental restructuring of interstate pipeline sales and transportation
services. Among other things, Order No. 636 requires interstate pipelines

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to "unbundle" their merchant sales functions from their transportation and
storage functions, requires interstate pipelines to assign capacity rights they
have on upstream pipelines to the pipelines' former sales customers and
provides for the recovery by interstate pipelines of costs associated with the
pipelines' transition from providing bundled sales services to providing
unbundled transportation and storage services. In August 1992, the FERC issued
an Order on Rehearing ("Order No. 636-A"), largely upholding the regulations
and requirements of Order No. 636. While Order Nos. 636 and 636-A would not
directly regulate National Energy's activities, the wide ranging implications
of those orders for the natural gas industry may have an indirect effect on
such activities. Among other things, Order No. 636 may increase
transportation costs and tariffs on interstate pipelines and cause interstate
pipelines to seek to renegotiate or terminate certain of their existing
purchase contracts, but ultimately may enhance gas marketing opportunities and
transportation availability.

Order Nos. 636 and 636-A are subject to further rehearing by the FERC
and court challenges. Although the outcome of these proceedings and the
various individual interstate pipeline restructuring proceedings required by
those Orders cannot be predicted with certainty, National Energy does not
believe the Orders will have an adverse effect on its operations or the Trust.
Nevertheless, the Orders have resulted in a degree of uncertainty with respect
to interstate natural gas sales and transportation because the precise effects
of the Orders will remain unknown for some time.

NO PRICE CONTROLS ON LIQUID HYDROCARBONS. Sales of crude oil,
condensate and natural gas liquids can be made at uncontrolled prices. There
are currently no price controls on crude oil, condensate or natural gas
liquids.

LEGISLATIVE PROPOSALS. In the past, Congress has been very active in
the area of natural gas regulation. Legislation recently enacted repeals
incremental pricing requirements and gas use restraints previously applicable.
There are other legislative proposals pending in the Federal and state
legislatures, which, if enacted, would significantly affect the petroleum
industry. At the present time it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures
and what effect, if any, such proposals might have on the Underlying Properties
and Trust.

STATE REGULATION. Many state jurisdictions have at times imposed
limitations on the production of natural gas by restricting the rate of flow
for natural gas wells below their actual capacity to produce and by imposing
acreage limitations for the drilling of a well. States may also impose
additional regulation of these matters. Most states regulate the production
and sale of oil and natural gas, including requirements for obtaining drilling
permits, the method of developing new fields, the spacing and operation of
wells and the prevention of waste of oil and gas resources. The rate of
production may be regulated and the maximum daily production allowable from oil
and natural gas wells may be established on a market demand or conservation
basis or both.

ENVIRONMENTAL REGULATION

GENERAL. Activities on the Underlying Properties are subject to
existing federal, state and local laws and regulations governing environmental
quality and pollution control. It is anticipated that, absent the occurrence
of an extraordinary event, compliance with existing federal, state and local
laws, rules and regulations regulating the discharge of materials in the
environment or otherwise relating to the protection of the environment will not
have a material effect upon the Trust. National Energy cannot predict what
effect additional regulation or legislation, enforcement policies thereunder,
and claims for damages to property, employees, other persons and the
environment resulting from operations on the Underlying Properties could have
on the Trust.

SOLID AND HAZARDOUS WASTE. The Underlying Properties have produced
oil and natural gas for several years and will be purchased by National Energy
only upon completion of the offering for Trust-A. Although, to National
Energy's knowledge, the operators have utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
solid wastes may have been disposed or released on or under the Underlying
Properties by the current or previous operator. State and federal laws
applicable to oil and gas wastes and properties have become increasingly more
stringent. Under these new laws, National Energy or an operator of the
Underlying Properties could be required to remove or remediate previously
disposed wastes or property contamination (including groundwater contamination)
or to perform redial plugging operations to prevent future contamination.

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<PAGE> 21
The operators of the Underlying Properties may generate wastes that
are subject to the Federal Resource Conservation and Recovery Act and
comparable state statutes. The Environmental Protection Agency ("EPA"), the
Oklahoma Corporation Commission and the Texas Railroad Commission have limited
the disposal options for certain hazardous wastes and are considering the
adoption of more stringent disposal standards for nonhazardous wastes.
Furthermore, it is anticipated that additional wastes (which could include
certain wastes generated by oil and gas operations) will be designated as
"hazardous wastes," which are subject to more rigorous an costly disposal
requirements.

SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability,
without regard to fault of the legality of the original conduct, or certain
classes of persons that contributed to the release of a "hazardous substance"
into the environment. These persons include the owner and operator of a site
and companies that disposed or arranged for the disposal of the hazardous
substance found at a site. CERCLA also authorizes the EPA and, in some cases,
third parties to take actions in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons
the costs of such action. In the course of their operations, the operators of
the Underlying Properties have generated and will generate wastes that may fall
within CERCLA's definition of "hazardous substances." National Energy or
operator of the Underlying Properties may be responsible under CERCLA for all
or part of the costs to clean up sites at which such wastes have been disposed.
National Energy has not been named a potentially responsible party in any
action brought under CERCLA.

AIR EMISSIONS. The operators of the Underlying Properties are subject
to federal, state and local regulations for the control of emissions from
sources of air pollution. Administrative enforcement actions for failure to
comply strictly with air regulations or permits are generally resolved by
payment of a monetary penalty and correction of any identified deficiencies.
Alternatively, regulatory agencies could require the operators to forego
construction or operation of certain air emission sources.

OSHA. The operators of the Underlying Properties are subject to the
requirements of the Federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of the federal Superfund
Amendment and Reauthorization Act, and similar state statutes require an
operator to organize information about hazardous materials used or produced in
its operations. Certain of this information must be provided to employees,
state and local governmental authorities and local citizens.

NATIONAL ENERGY

GENERAL

National Energy was formed as a California corporation in August,
1994. National Energy's principal executive office is located at 21800 Burbank
Blvd., Suite 100, Woodland Hills, California 91364, and its telephone number is
(800) 201-8666.

BUSINESS

National Energy is a development stage company organized to engage in
the acquisition, exploitation and development of producing properties and
related facilities, the exploration for oil and natural gas and the production,
marketing and transportation of oil and natural gas. National Energy has
entered into contracts to acquire five properties, located in Oklahoma.

National Energy's offices are located in Woodland Hills, California,
in approximately 1,200 square feet of leased space. National Energy also
maintains a leased field office in Enid, Oklahoma with Blackjack.

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MANAGEMENT

The business and affairs of National Energy are controlled by its
Board of Directors which is composed of 1 member. The officers of National
Energy are elected by and serve until their successors are appointed by its
Board of Directors. The directors and executive officers of National Energy
are as follows:

Name Title
---- -----
Marshall J. Field President and Director

Set forth below is the business experience during the past five years
of the directors and executive officers of National Energy.

Marshall J. Field, age 46, has been President and Director of National
Energy Resources, Inc. since its formation in August, 1994. Mr. Field
currently serves as Chief Executive Officer and President of Marshall Field &
Company under Spectrum Securities. Mr. Field was Executive Vice President of
United California Securities, from June of 1994 to January 1996. From December
1993 until June 1994, Mr. Field was with American Business Securities. From
July 1991 until December 1993 Mr. Field was with Southern California
Securities. He has served as a registered representative in several major
brokerage firms, including Prudential Bache from September 1985 to July 1989
and PaineWebber from July 1989 to July 1991. His background in the industry
spans eighteen years of experience in income investments. Mr. Field has been a
regular on "The Interest Rate Report" on KWHY-TV for the past eight years. Mr.
Field was educated at California State Northridge and Santa Monica College in
California.

EMPLOYEES

National Energy had no employees as of May 28, 1996.

CONSULTANTS

F. W. Elton in an independent consulting engineer, performing
engineering and some geological duties depending upon the clients' need and
wishes. Mr. Elton has performed mineral valuations for banks, estate work for
attorneys, valuations for producers and royalty owners. In addition, he does
open hole log and sample interpretations; prepares procedure and cost
estimates; supervises drilling, completion and remedial and day to day
production operations. His work has covered Oklahoma, Central and Southeast
Kansas, Northwest Mississippi and a portion of Arkansas. From July 1949 to
March 1976 Mr. Elton was employed by Shell Oil Company holding the position of
Petroleum Engineer (1949-1958) and Production Foreman (1958-1976). Mr. Elton
retired from Shell Oil Company in 1976. Mr. Elton has an M.E. Degree from the
Colorado School of Mines, Golden, Colorado. Mr. Elton served in the United
States Air Force from 1942 until 1945, in the Colorado National Guard from 1946
until 1949 and the Army Reserve Corps of Engineers from 1949 until 1953.

BLACKJACK

Blackjack Oil & Gas, Inc., which operates all of the Underlying
Properties from which Trust-A will derive its revenues, is a corporation formed
in 1983 in Oklahoma. It employs six people and operates over 65 wells in
Oklahoma. Blackjack's offices are located at 1633 West Garriott Road, Suite D,
Enid, Oklahoma 73703. Its officers and key employees are:

Gary Foster, age 52. Mr. Foster is the owner of Blackjack and prior
to starting Blackjack in 1983, he was the co-owner of Oil Operating Company and
was an independent oil and gas landman. Mr. Foster received a B.A. degree in
1966 and a M.A. degree in 1972 from the University of Northern Colorado and did
post-graduate study at the University of Northern Colorado, University of
Nebraska and Missouri Western.

Tom Gilbert, age 46. Mr. is the Production Superintendent. He has
been engaged in the oil and gas business for 24 years. Mr. Gilbert was the
Area Manager (Rocky Mountain District) for Pool Well Service from

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1986-1994 before being employed at Blackjack. He worked for various other well
service companies from 1972-1986. He has supervised both the drilling and
completion of wells.

CERTAIN TRANSACTIONS

National Energy is purchasing the Underlying Properties from Blackjack
Oil & Gas, Inc. who is the operator of the wells. The purchase price for the
Underlying Properties is $508,000 and is based upon a present value
determination of the wells by National Energy's consulting engineer using
reserve reports, production information and other well data. The purchase
price paid by National Energy to Blackjack is greater than the Production
Payment sales price from National Energy to the Trust. Mr. Marshell, the
principal of National Energy, will contribute sufficient capital to National
Energy to complete the accquisition.

FEDERAL INCOME TAX CONSEQUENCES

GENERAL

This section summarizes the principal Federal income tax consequences
of the ownership and sale of the Trust Units. The laws, regulations, court
decisions and IRS interpretations on which this summary is based are subject to
change by future legislation, regulations or new interpretations by the courts
or the IRS, which could have an adverse effect on the ownership of Trust Units.
National Energy will not request advance rulings from the IRS dealing with the
tax consequences of ownership of Trust Units but will rely on the opinion of
Counsel, Robertson & Williams, Inc., Oklahoma City, Oklahoma, regarding the
classification of the Trust and certain tax consequences described below.
Consummation of the offering is conditioned upon the confirmation of Counsel's
opinion at the time of the closing. Counsel believes that its opinion is in
accordance with the present position of the IRS regarding such trusts. Such
opinion is not binding on the IRS or the courts, however, and no assurance can
be given that the IRS or the courts will agree with such opinion.

CLASSIFICATION AND TAXATION OF THE TRUST

In the opinion of Counsel, under current law, the Trust will be
taxable as a grantor trust and not as an association taxable as a corporation.
As a grantor trust, the Trust will not be subject to tax at the trust level.
For tax purposes, the grantors (in this case, the Trust Unitholders) will be
considered to own the Trust's income and principal as though no trust were in
existence. A grantor trust simply files an information return, reporting all
items of income, credit or deductions which must be included in the tax returns
of the grantors. If, contrary to the opinion of Counsel, the Trust were
determined to be an association taxable as a corporation, it would be treated
as a separate entity subject to normal corporate tax on its taxable income, the
Trust Unitholders would be treated as shareholders, and distribution to Trust
Unitholders would be treated as nondeductible corporate distributions. Such
distributions would be taxable to a Trust Unitholder, first, as dividends to
the extent of the Trust Unitholder's pro rate share of the Trust's deemed
earnings and profits, then as a tax-free return of capital to the extent of his
basis in his Trust Units, and finally as capital gain to the extent of any
excess. In the absence of any legislative change or other development deemed
adverse by the Trustee, the Trustee does not intend to set aside any reserve
for possible Federal income taxes imposed on the Trust.

DIRECT TAXATION OF TRUST UNITHOLDERS

Since the Trust will be treated as a grantor trust for Federal income
tax purposes, each Trust Unitholder will be taxed directly on his pro rata
share of the income of the Trust and will be entitled to claim his pro rata
share of the deductions of the Trust. The income of the Trust will be deemed
to have been received or accrued by the Trust Unitholders at the time such
income is received or accrued by the Trust and not when distributed by the
Trust. Income and expenses of the Trust will be taken into account by Trust
Unitholders consistent with their method of accounting and without regard to
the taxable year or accounting method employed by the Trust.

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INTEREST INCOME

Based on representations made by National Energy, the reserves to be
burdened by each Production Payment acquired by a Trust and the expected term
of each Production Payment will be such that the Production Payments will meet
the definition of a "production payment" under Section 636(a) of the Code.
Thus, each Trust Unitholder will be treated as making a mortgage loan on the
Underlying Properties to National Energy in an amount equal to the purchase
price of each Trust Unit less interest on the Reserve Fund.

REPORTING OF TRUST INCOME AND EXPENSES

Unless otherwise advised by Counsel or the IRS, the Trustee intends to
treat the interest portion of each production payment it receives as the
taxable income of the Trust Unitholders of record on the day of receipt (i.e.,
the first business day of each calendar month). Similarly, the Trustee intends
to pay expenses only on the day it receives a production payment and to treat
all expenses paid on a production payment receipt day as the expenses of the
Trust Unitholder to whom the royalty income received on that date is
distributed. Interest earned on a distribution amount will be treated as
belonging to the Trust Unitholder to whom the distribution amount is paid.
Interest earned on the Reserve Fund will not be distributed and will be
allocated to income. In most cases, therefore, the income and expenses of the
Trust for a period will be reported as belonging to the Trust Unitholder to
whom the distribution is made for such period and the amount of the
distribution for a Trust Unit will equal the net income allocated in respect of
such Trust Unit other than the amount of interest earned on the Reserve Fund.
It is possible that the IRS will attempt to impute income to persons who are
Trust Unitholders when a production payment accrues, to disallow administrative
expenses to persons who are not Trust Unitholders when the expenses are
incurred, or both. If the IRS did attempt to impute such income, an accrual
basis Trust Unitholder might realize royalty income in a tax year earlier than
that reported by the Trustee.

OTHER INCOME AND EXPENSES

It is anticipated that the only other income of the Trust will be
interest income earned on funds held as a reserve for payment of the original
investment by Trust Unitholders on termination of the Trust, or funds held
until the next distribution date. Other expenses of the Trust will include any
state and local taxes imposed on the Trust and administrative expenses of the
Trustee. Although the issue has not been definitely resolved, Tax Counsel
believes that all or substantially all of such expenses are deductible in
computing adjusted gross income and, therefore, are not the type of
miscellaneous itemized deductions that are allowable only to the extent that
the aggregate of such deductions exceeds 2% of adjusted gross income.

NON-PASSIVE ACTIVITY INCOME AND LOSS

The income and expenses of the Trust will not be taken into account in
computing the passive activity losses and income under Code Section 469 for a
Trust Unitholder who acquires and holds Trust Units as an investment.

SALE OF TRUST UNITS

Generally, a Trust Unitholder will realize gain or loss on the sale or
exchange of his Trust Units measured by the difference between the amount
realized on the sale or exchange and his adjusted basis for such Trust Units.
Gain or loss on the sale of Trust Units by a Trust Unitholder who is not a
dealer with respect to such Trust Units and who has a holding period for the
Trust Units of more than one year will be treated as long-term capital gain or
loss. A Trust Unitholder's basis in his Trust Units will be equal to the
amount paid for such Trust Units pursuant to this offering or pursuant to
market transactions. It is possible that the IRS would take the position that
a portion of the sales proceeds is ordinary income to the extent of any accrued
income at the time of sale allocable to the Trust Units sold, but which is not
distributed to the selling Trust Unitholder.

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BACKUP WITHHOLDING

In general, distributions of Trust income will not be subject to
"backup withholding" unless: (i) the Trust Unitholder is an individual or other
noncorporate taxpayer and (ii) such Trust Unitholder fails to comply with
certain reporting procedures.

REGISTRATION PROVISION

Tax shelter offerings must register with the Service on a form which
includes a brief description of the tax shelter and the promoter. National
Energy believes the Trusts are not tax shelters for the purpose of this
registration requirement.

Ownership of the Production Payment by the Trust may subject Trust
Unitholders to tax in states in which the Underlying Properties are located as
well as the state in which a Trust Unitholder resides or is domiciled.
Prospective Trust Unitholders should consult their own tax advisors regarding
the impact of state and local taxes on their proposed investments.

ERISA CONSIDERATION

The Employee Retirement Income Security Act of 1974, as amended
("ERISA"), imposes certain requirements on pension, profit-sharing and other
employee benefit plans to which it applies ("Plans"), and contains standards on
those persons who are fiduciaries with respect to such Plans. In addition,
under the Code, there are similar requirements and standards which are
applicable to certain Plans and individual retirement accounts (whether or not
subject to ERISA) (collectively, together with Plans subject to ERISA, referred
to herein as "Qualified Plans").

A fiduciary of a Qualified Plan should carefully consider fiduciary
standards under ERISA regarding the Plan's particular circumstances before
authorizing an investment in Trust Units. A fiduciary should first consider
(i) whether the investment satisfies the prudence requirements of Section
404(a)(1)(B) of ERISA, (ii) whether the investment satisfies the
diversification requirements of Section 404(a)(1)(C) of ERISA and (iii) whether
the investment is in accordance with the documents and instruments governing
the Plan as required by Section 404(a)(1)(D) of ERISA.

In order to avoid the application of certain penalties, a fiduciary
must also consider whether the acquisition of Trust Units and/or operation of
the Trust might result in direct or indirect nonexempt prohibited transactions
under Section 406 of ERISA and Code Section 4975. In determining whether there
are such prohibited transactions, a fiduciary must determine whether these are
"plan assets" involved in the transaction. On November 13, 1986, the
Department of Labor published final regulations (the "DOL Regulations")
concerning whether or not a Qualified Plan's assets (such as a Trust Unit)
would be deemed to include an interest in the underlying assets of an entity
(such as the Trust) for purposes of the reporting, disclosure and fiduciary
responsibility provisions of ERISA and analogous provisions of the Code, if the
Plan acquires an "equity interest" in such entity. The DOL Regulations provide
that the underlying assets of an entity will not be considered "plan assets" if
the interests in the entity are a publicly offered security. Trust Units are
considered to be "publicly offered" for this purpose if they are part of a
class of securities that is (i) widely held (i.e., owned by more than 100
investors independent of the issuer and each other), (ii) freely transferable,
and (iii) registered under Section 12(b) or 12(g) of the Exchange Act.
Fiduciaries, will need to determine whether the acquisition of Trust Units is a
nonexempt prohibited transaction under the general requirements of ERISA
Section 406 and Code Section 4975.

Due to the complexity of the prohibited transaction rules and the
penalties imposed upon persons involved in prohibited transactions, it is
important that potential Qualified Plan investors consult with their counsel
regarding the consequences under ERISA and the Code of their acquisition and
ownership of Trust Units.

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DESCRIPTION OF THE TRUST AGREEMENT

The following information and the information set forth under
"Description of the Trust Units" are subject to the detailed provisions of the
Trust Agreement between National Energy and Boatmen's Trust Company which acts
as Trustee for the Trust. The following is a general description of the basic
framework of the Trust, and is qualified by the detailed provisions concerning
the Trust set forth in the Agreement, a copy of which was filed as an exhibit
to the Registration Statement. See "Available Information." For a description
of the fiduciary responsibility of the Trustee, including remedies available
for the breach of these duties, see "-- Fiduciary Responsibility and Liability
of the Trustee," below.

CREATION AND ORGANIZATION OF THE TRUST; AMENDMENTS

Pursuant to the Conveyances, the Production Payments will be conveyed
by National Energy to the Trust in exchange for net proceeds from this
offering. The Trust Units are being offered by Trust-A pursuant to this
Prospectus and by Prospectus Supplements relating to Trusts yet to be formed
for the remaining Trust Units.

The Trust will be created under Oklahoma law pursuant to the terms of
the Agreement to acquire and hold the Production Payment for the benefit of the
Trust Unitholders. The Production Payment is passive in nature and the Trustee
will have no control over and no responsibility for costs relating to the
operation of the Underlying Properties. Neither National Energy nor the
operators of the Underlying Properties have any contractual commitments to the
Trust to conduct further drilling on the Underlying Properties nor to maintain
their ownership interest in any of such properties. For a description of the
Underlying Properties and other information relating to such properties, see
"Production Payment and the Underlying Properties."

The beneficial interest in the Trust-A is divided into 500 Trust
Units, which represent equal undivided portions. For additional information
concerning the Trust Units, see "Description of the Trust Units."

The Agreement may be amended by a vote of holders of 80% of the Trust
Units. No provision of the Agreement, however, may be amended that would
increase the power of the Trustee to engage in business or investment
activities or to alter the rights of the Trust Unitholders as among themselves.

ASSETS OF THE TRUST

The only assets of the Trust, other than cash and temporary
investments being held for the payment of expenses, and for distribution to the
Trust Unitholders, are the Reserve Funds and the Production Payments. See "The
Production Payments and the Underlying Properties."

DUTIES AND LIMITED POWERS OF THE TRUSTEE

The duties of the Trustee are specified in the Agreement and by the
laws of Oklahoma. The basic duties of the Trustee are to collect income
attributable to the Production Payment to pay out of the Trust's income and
assets all expenses, charges and obligations and to distribute the
distributable income to the Trust Unitholders. The Trustee is authorized to
take such action as in its judgment is necessary or advisable to best achieve
the purposes of the Trust.

After payment of or provision for Trust expenses and obligations, the
Trustee will make semi-annual distributions to the Trust Unitholders of certain
proceeds received from the Production Payments to pay the interest portion and
reserve the balance in a Reserve Fund to repay the Trust Unit investment amount
at the termination of the Production Payment. The Trustee will submit periodic
financial reports to the Trust Unitholders as described under "Description of
the Trust Units -- Periodic Reports."

The Agreement provides that cash being held by the Trustee as a
reserve for liabilities, the Reserve Fund, or for distribution at the next
distribution date will be invested in interest-bearing obligations of the
United States government, agreements secured by such obligations or
certificates in certain banks or similar investment grade securities which may
be recommended by National Energy, but the Trustee is otherwise prohibited from
acquiring

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<PAGE> 27
any asset other than the Production Payments or engaging in any business or
investment activity of any kind whatsoever.

In the event the Trustee determines it to be in the best interest
Trust Unitholders, the Trustee may sell or dispose of all or any part of the
Production Payments only as authorized by a vote of holders of 80% or more of
the Trust Units, or upon termination of the Trust. However, the Trustee is
directed to effect such a sale (without any such vote) if National Energy
exercises the option to repurchase the Production Payment after 2 years from
the date of formation of the Trust. Any such sale must be for cash and the
Trustee must distribute the net proceeds of such sale to the Trust Unitholders.

The Agreement also provides that in the event of certain judicial or
administrative proceedings seeking the cancellation or forfeiture of any
property included in the Underlying Properties or asserting the invalidity of
or otherwise challenging the Production Payments held by the Trust because of
the nationality, or any other status, of any one or more Trust Unitholders, the
Trustee will have the right to require such holder to dispose of his Trust
Units, and if such person fails to dispose of his Trust Units, the Trustee will
have the right to purchase such Trust Units.

To achieve the purposes of the Trust, the Trustee is also authorized
to agree to modifications of the terms of the Conveyances or to settle disputes
with respect thereto, so long as such modifications or settlements do not alter
the nature of the Production Payments as to rights to receive a share of the
proceeds of oil or natural gas produced from the Underlying Properties, free of
any expense or other cost.

LIABILITIES OF THE TRUST

Because of the passive nature of the Trust assets and the restrictions
on the power of the Trustee to incur obligations, it is anticipated that the
only liabilities the Trust will incur will be those for routine administrative
expenses, such as the Trustee's fees, clerical expenses and accounting, legal
and other professional fees.

FIDUCIARY RESPONSIBILITY AND LIABILITY OF THE TRUSTEE

The Trustee is a fiduciary with respect to the Trust Unitholders and
under Oklahoma law, the Trustee is required to act in the best interests of the
Trust Unitholders at all times and to exercise the judgment and care in
supervising and managing the Trust's assets exercised by persons of ordinary
prudence, discretion and intelligence. Under Oklahoma law, the Trustee's
duties to the Trust Unitholders are similar to the duties of a director of a
corporation to the shareholders of the corporation, except that the legal
presumption protecting business decisions made by directors from challenge,
generally referred to as the business judgment rule, is inapplicable to
decisions by the Trustee.

Due to the passive nature of the Trust, the Trustee is not expected to
make business decisions affecting the assets of the Trust. Therefore,
substantially all of the Trustee's functions under the Trust Agreement are
anticipated to be ministerial in nature. See " -- Duties and Limited Powers of
the Trustee," above. Under Oklahoma law, the Trustee may not profit from any
transaction with the Trust except that the Trust Agreement permits the Trustee
to charge for its services as trustee and as transfer agent (see "--
Compensation of the Trustee"), to retain funds to pay anticipated future
expenses and to deposit such funds with the Trustee and to borrow funds at
commercial rates from the Trustee to pay expenses of the Trust. The Trustee
will also be entitled to receive reimbursement of out-of-pocket expenses
incurred in administering the Trust.

In discharging its fiduciary duty to the Trust Unitholders, the
Trustee may act in its discretion and shall be personally or individually
liable to the Trust Unitholders only for fraud or acts or omissions
constituting bad faith and will not be liable for any act or omission of any
agent or employee of the Trustee unless the Trustee has acted in bad faith in
the selection and retention of such agent or employee. The Trustee will be
indemnified for any liability, expense, claim, damage or other loss incurred by
it individually or as Trustee in the administration of the Trust or for any act
or omission on account of it being Trustee, unless resulting from fraud or bad
faith, and the Trustee will have a lien upon the assets of the Trust as
security for such indemnification and reimbursement and for compensation to be
paid to the Trustee. The Trustee shall not be entitled to indemnification from
Trust Unitholders.

25
<PAGE> 28
See "Description of the Trust Units -- Liability of Trust Unitholders." The
Trustee is required to ensure that all contractual liabilities of the Trust are
limited to the assets of the Trust and will be liable to the Trust Unitholders
if it fails to do so.

Under Oklahoma law, if the Trustee, in bad faith, were to fail to
collect amounts owed to the Trust or distribute cash held by the Trust for
distribution, or otherwise, in bad faith, take or omit to take any action that
is in the best interest of the Trust Unitholders, the Trustee would be liable
to the Trust Unitholders for damages caused by any such act or omission,
including any loss or depreciation in value of the Trust Assets or failure to
make a profit from such assets caused by such act or omission. Oklahoma law
permits Trust Unitholders to file an action seeking other remedies for such
acts or omissions in addition to damages, including removal of the Trustee,
specific performance, appointment of a receiver, an accounting by the Trustee
to the Trust Unitholders, exemplary damages and other remedies. The
availability of these remedies provided by Oklahoma law is explicitly
incorporated into the Agreement. Under the Agreement, the Trustee may be
removed by the Trust Unitholders, with or without cause, by the affirmative
vote of the holders of a majority of the Trust Units.

RESERVE FUND

The Agreement requires the Trustee to establish a Reserve Fund for
that portion of the payments received from the Production Payment which are
allocable to the repayment of the Primary Sum or principal amount. The Trustee
may also set aside sums in the Reserve Fund for contingent or future expenses
of the Trust or the Trustee or to fund any account. The amounts included in
the Reserve Fund are to be invested in U. S. government obligations,
certificates of deposit of any bank having capital, surplus and undivided
profits in excess of $100,000,000, including the bank affiliated with the
Trustee or similar investment grade securities which may be recommended by
National Energy to the Trustee.

Upon termination of the Trust, the Reserve Fund, after payment of
Trust liabilities, if any, will be distributed to the Unitholders as a return
of their initial contributions.

DURATION OF THE TRUST; SALE OF PRODUCTION PAYMENT

The Trust will be terminated upon payment in full of the Production
Payment or the sale by the Trust of all or substantially all of the Production
Payments, which sale may be effected only as described under "-- Duties and
Limited Powers of the Trustee," above. The Trust may also be terminated by a
vote of holders of 80% or more of the Trust Units outstanding or upon operation
of the provisions of the Agreement intended to permit the Trust to comply with
the "rule against perpetuities." Upon termination of the Trust, the Trustee
will sell for cash in one or more sales (which may be public auctions) all of
the assets then constituting the Trust estate. After paying all liabilities of
the Trust and establishing any reserves that the Trustee deems appropriate for
contingent liabilities, the Trustee will distribute the proceeds of such sales
and any other cash in the Trust estate to Trust Unitholders according to their
respective interests. The Trustee will not be required to obtain approval of
Trust Unitholders prior to conducting any sales upon termination of the Trust.

The Trustee may cause the sale of the Production Payment held by a
Trust if the holders of 80% or more of the Trust Unitholders of that Trust
approve such sale or if National Energy exercises its option to repurchase the
Production Payment at any time after 2 years from the formation of the Trust.
The net proceeds of such sale will be distributed to the Trust Unitholders.
Sale of the Production Payment will terminate the Trust.

COMPENSATION OF THE TRUSTEE

The Agreement provides that the Trustee will be compensated for its
services, out of the Trust assets, in an annual amount of Twelve Hundred
Dollars ($1200.00). The Trustee will also be entitled to reimbursement for its
out-of- pocket expenses.

26
<PAGE> 29
MISCELLANEOUS

The Agreement provides that the Trustee may, but is not required to,
consult with counsel (which may be counsel to National Energy or its
successors), accountants, geologists, engineers and other parties deemed by the
Trustee to be qualified as experts on the matters submitted to them, and the
Trustee will be authorized and protected with respect to any action taken or
suffered by the Trustee in good faith in reliance upon and in accordance with
the opinion of any such party.

DESCRIPTION OF THE TRUST UNITS

GENERAL

National Energy is the sponsor of a series of trusts offering up to
6,000 units of beneficial interests ("Trust Units"). The Trust Units will be
issued on the Closing Date of each Trust. Each Trust Unit represents an
undivided share of beneficial interest in a National Energy Trust and entitles
its holder to the same rights as the holder of any other Trust Unit in that
Trust. Trust-A will be the first trust formed and will have 500 Trust Units
outstanding. Each Trust will offer a minimum of 500 Trust Units for a possible
total of 12 grantor trusts to be formed during the 12 month period following
the effective date of registration of the Trust Units.

DISTRIBUTIONS AND INCOME COMPUTATIONS

The amount received each month by the Trustee on behalf of Trust-A
will be 78% of the Net Cash Flow from the Underlying Properties. Of this
amount, $62,500.00 will be allocated to interest earned on the Production
Payment, one- half of which will be distributed to Trust Unitholders
semi-annually. Excess will be allocated to the repayment of the Primary Sum
and will be added to the Reserve Fund. If at the end of any 12 month period
following the date of the Conveyance of Production Payment the Reserve Fund
does not meet or exceed a specified amount necessary to amortize the Primary
Sum over 5 years, the percentage of Net Cash Flow will increase to 100% until
the Reserve Fund meets or exceeds the required amount.

Unless otherwise advised by counsel or the IRS, the income and expense
of the Trust for each Semi-Annual Period will be reported by the Trustee for
tax purposes as belonging to the Trust Unitholders of record on the Semi-Annual
Record Date, to whom the Semi-Annual Distribution Amount for that Semi-Annual
Period will be distributed. The income and expense will be recognized by the
Trust Unitholders for tax purposes in the Semi-Annual Period received or paid
by the Trust, rather than in the Semi-Annual Period distributed by the Trust.
Net income, apart from any depletion to which a Trust Unitholder may be
entitled, is expected to be essentially the same as the Semi-Annual
Distribution Amount. However, there will be variances because of the
establishment of the Reserve Fund and the possibility that, for example, a
reserve will be established in one Semi-Annual Period that will not give rise
to a tax deduction until a subsequent Semi-Annual Period or an expenditure paid
in one Semi-Annual Period will have to be amortized for tax purposes over
several monthly periods. See "Federal Income Tax Consequences."

TRANSFER OF TRUST UNITS

Trust Units will be transferable on the records of the Trustee upon
the surrender of any Certificate in proper form for transfer as required by the
Trustee. No service charge will be made to the transferor or transferee for
any transfer of a Trust Unit, but the Trustee may require payment of a sum
sufficient to cover any tax or other governmental charge that may be imposed in
connection with such transfer. Until any such transfer, the Trustee may treat
the owner of any Trust Unit as shown by its records as the owner of the Trust
Units evidenced thereby and the Trustee shall not be charged with notice of any
claim or demand respecting such Certificate or the interest represented thereby
by any other party. Any such transfer of a Trust Unit shall, as to the
Trustee, transfer to the transferee as of the close of business on the date of
transfer, all right, title and interest of the transferor in and to the Trust;
provided, that a transfer of a Trust Unit after any Monthly Record Date shall
not transfer to the transferee the right of the transferor to the Monthly
Distribution Amount relating to such date. As to matters affecting the title,
ownership, warranty or transfer of the Certificates and the Trust Units
represented thereby, the law from time to time in force in the State of
Oklahoma with respect to the transfer of securities shall govern.

27
<PAGE> 30
PERIODIC REPORTS

The Trustee will mail to the Trust Unitholders of record as of a date
to be selected by the Trustee an annual report containing audited financial
statements of the Trust.

The Trustee will file such returns for Federal income tax purposes as
in its judgment are required to comply with applicable law, and the Trustee
will prepare and mail to the Trust Unitholders annually such reports as may be
necessary to permit each Trust Unitholder to report correctly his share of the
income and deductions of the Trust. The Trustee intends to treat all income
and deductions recognized during each Semi-Annual Period as having been
recognized by holders of record on the last business day of such Semi-Annual
Period unless otherwise advised by counsel or the IRS.

Each Trust Unitholder and his duly authorized agents and attorneys
shall have the right during reasonable business hours to examine and inspect
records of the Trust and the Trustee including a list of the Trust Unitholders.

LIABILITY OF TRUST UNITHOLDERS

The Trustee is under a duty not to incur any liability without
ensuring that such liability will be satisfied only out of the Trust assets
(regardless of whether the assets are adequate to satisfy the liability) and in
no event out of amounts distributed to, or other assets owned by, Trust
Unitholders. However, under the law of Oklahoma, it is unclear whether a Trust
Unitholder would be jointly and severally liable for any liability of the Trust
in the event that the following conditions were to occur: (a) the satisfaction
of such liability was not by contract limited to the assets of the Trust; and
(b) insurance proceeds and the assets of the Trust or Trustee were insufficient
to discharge such liability. National Energy believes that because of the
value and passive nature of the Trust assets and the restrictions on the power
of the Trustee to incur liabilities, the imposition of any liability on a Trust
Unitholder is remote.

VOTING RIGHTS OF TRUST UNITHOLDERS

While Trust Unitholders will have certain voting rights, such rights
differ from and are more limited than those of stockholders of most public
corporations. For example, there is no requirement for annual meetings of
Trust Unitholders or for annual or other periodic reelection of the Trustee.

Meetings of Trust Unitholders may be called by the Trustee and the
Trust Unitholders owning not less than 15% of the Trust Units outstanding may
direct the Trustee to call a meeting. All such meetings must be held in
Encino, California, and written notice setting forth the time and place of such
meeting and the matters proposed to be acted upon shall be given not more than
60 days nor less than 20 days before such meeting to all of the Trust
Unitholders of record. The presence in person or by proxy of Trust Unitholders
representing a majority of the Trust Units outstanding is necessary to
constitute a quorum. Unless otherwise required by the Trust Indenture, any
matter shall be deemed to have been approved by the Trust Unitholders if it is
approved by the vote of a majority in interest of such Trust Unitholders
constituting a quorum, although less than a majority of the Trust Units then
outstanding. Each Trust Unitholder shall be entitled to one vote for each
Trust Unit owned by such holder.

The Trustee may be removed, with or without cause, by a vote of the
holders of a majority of the outstanding Trust Units. The following matters
require the affirmative vote of the holders of 80% of the outstanding Trust
Units: (i) the termination of the Trust; (ii) the amendment of the Trust
Indenture; and (iii) the approval of the sale of all or any part of the assets
of the Trust.

The sale of all or any part of the assets of the Trust requires the
prior consent of the Trustee except in connection with the termination of the
Trust.

28
<PAGE> 31
PLAN OF DISTRIBUTION

COMMISSIONS

Trust Units will be offered on a best efforts basis by a group of
member firms of the National Association of Securities Dealers, Inc. (the
"NASD"), (such member firms hereafter are referred to as "Soliciting Dealers")
which will be selected by National Energy. Each Soliciting Dealer will receive
from the Trust a commission of up to 8% of the purchase price of Trust Units
sold by such Soliciting Dealer on the Closing Date.

INDEMNIFICATION

National Energy, the Trust and the Soliciting Dealers have agreed to
indemnify each other against certain civil liabilities, including liabilities
arising under the 1933 Act.

SUBSCRIPTION PROCEDURES AND PAYMENTS

Persons intending to subscribe should send one signed Subscription
Agreement with the number of Trust Units desired indicated thereon to Boatmen's
Trust Company, Escrow Agent, at P. O. Box 25189, Oklahoma City, Oklahoma 73125-
0189, Attn: Corporate Trust Department, together with a check in the full
amount subscribed payable to Boatmen's Trust Company, Escrow Agent." A
subscription will be binding and enforceable upon a subscriber if within 15
days after the Escrow Agent's receipt of the Subscription Agreement, National
Energy evidences its acceptance by countersigning said Subscription Agreement.
National Energy will not knowingly accept subscriptions from persons who fail
to meet the suitability standards. See "Plan of Distribution -- Suitability
Standards." Each subscription payment will be held by the Escrow Agent in a
trust account until either (1) deposited to the account of the Trust on the
Closing Date or (2) refunded to the subscriber with any interest earned thereon
as soon as possible should it be determined that the offering will not be
consummated.

SUITABILITY STANDARDS

The investment offered hereby represent a long-term investment without
liquidity, which investment involves significant risks, and should be
considered only by persons with substantial financial means who have no need
for liquidity in this investment.

A potential investor will be required to furnish information in the
Subscription Agreement sufficient to satisfy National Energy that the
investment is suitable in light of his or her other security holdings and
financial situation and needs, and that her or she, has such knowledge and
experience in financial and business matters that he or she is capable of
evaluating the merits and risks of the proposed investment.

A potential investor must be able to represent that he or she: (i) has
a net worth of at least $225,000 (exclusive of home, home furnishings and
personal automobiles); or (ii) has a net worth of $75,000 (exclusive of home,
home furnishings and personal automobiles) and has and anticipates that he or
she will continue to have, in the future, annual taxable income of $75,000 or
more, without regard to any taxable income which may be generated by the
investment in the Trust and that the investment will not exceed 10% of his or
her net worth.

VALIDITY OF SECURITIES

The validity of the Trust Units offered hereby will be passed upon for
National Energy by Robertson & Williams, an Oklahoma Professional Corporation.

29
<PAGE> 32
EXPERTS

Certain information appearing in this Prospectus regarding the
estimated quantities of reserves of the oil and gas properties owned by the
Trust, the future net revenues from such reserves and the present values
thereof is based on estimates of such reserves and present values prepared by
F.W. Elton, Inc., an independent petroleum engineering firm.

The audited financial statements included in this Prospectus have been
audited by Museck & Museck, independent accountants, as stated in their reports
appearing herein, and have been so included in reliance upon such reports given
upon the authority of that firm as experts in accounting and auditing.

30
<PAGE> 33
INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
NATIONAL ENERGY RESOURCES, INC.

Independent Auditor's Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1

Balance Sheet as of July 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-2

Income Statement for Year Ended July 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-4

Statement of Stockholders' Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6

Statement of Retained Earnings for Year Ended July 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7

Statement of Cash Flows for Year Ended July 31, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-8

Unaudited Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-9

Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-14
</TABLE>

31
<PAGE> 34
[MUSECK & MUSECK LETTERHEAD]

INDEPENDENT AUDITORS' REPORT

To the Board of Directors
National Energy Resources, Inc.

We have audited the accompanying balance sheet of National Energy Resources,
Inc. (a development stage company) as of July 31, 1995, and related statements
of income, retained earnings, stockholders' equity, and cash flows for the year
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 audit.

We conducted our audit in accordance with generally accepted auditing standards.
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 audit provides 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 National Energy Resources as
of July 31, 1995, and the results of its operations and its cash flows for the
year then ended in conformity with generally accepted accounting principles.

/s/ MUSECK & MUSECK

New Providence, New Jersey
May 23, 1996

F-1
<PAGE> 35
NATIONAL ENERGY RESOURCES, INC.
BALANCE SHEET
JULY 31, 1995

ASSETS

<TABLE>
<S> <C> <C> <C>
CURRENT ASSETS
PETTY CASH $ 420
---------
TOTAL CURRENT ASSETS $ 420

PROPERTY AND EQUIPMENT
INTANGIBLE ASSETS $ 6,066
LESS-ACCUMULATED AMORTIZATION 708 5,358
-------- ---------
TOTAL PROPERTY AND EQUIPMENT 5,358

OTHER ASSETS
DEFERRED ISSUE COSTS 19,050
---------
TOTAL OTHER ASSETS 19,050
--------
TOTAL ASSETS $ 24,828
========
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-2
<PAGE> 36
NATIONAL ENERGY RESOURCES, INC.
BALANCE SHEET
JULY 31, 1995

LIABILITIES

<TABLE>
<S> <C> <C>
CURRENT LIABILITIES
ACCOUNTS PAYABLE $ 10,319
ACCRUED OTHER STATE TAXES 800
-------------
TOTAL CURRENT LIABILITIES $ 11,119

LONG-TERM LIABILITIES
LOANS FROM STOCKHOLDERS 14,217
-------------
TOTAL LONG-TERM LIABILITIES 14,217

STOCKHOLDERS' EQUITY
COMMON STOCK 1,000
RETAINED EARNINGS - UNAPPROPRIATED (1,508)
-------------
TOTAL STOCKHOLDERS' EQUITY (508)
---------
TOTAL LIABILITIES/STOCKHOLDERS' EQUITY $ 24,828
=========
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-3
<PAGE> 37

NATIONAL ENERGY RESOURCES, INC.
STATEMENT OF INCOME
FOR THE PERIOD ENDED JULY 31, 1995

<TABLE>
<S> <C>
GENERAL/ADMINISTRATIVE EXPENSES - SCHEDULE A $ 1,508
-----------
OPERATING PROFIT (1,508)
-----------
NET INCOME $ (1,508)
===========
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-4
<PAGE> 38
NATIONAL ENERGY RESOURCES, INC.
SUPPORTING SCHEDULES
FOR THE PERIOD ENDED JULY 31, 1995

<TABLE>
<S> <C>
SCHEDULE A - GENERAL AND ADMINISTRATIVE

AMORTIZATION $ 708
STATE FILING FEE 800
--------------
TOTAL GENERAL AND ADMINISTRATIVE EXP $ 1,508
==============
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-5
<PAGE> 39
NATIONAL ENERGY RESOURCES, INC.
(A Development Stage Company)
STATEMENT OF STOCKHOLDERS' EQUITY

COMMON STOCK
-------------------------
NUMBER OF
SHARES VALUE
-------- -------
<S> <C> <C>
DATE OF INCORPORATION, AUGUST 8, 1994 -0- $ -0-

SHARES ISSUED FOR CASH ON AUGUST 15, 1994 1,000 1,000
----- -------
BALANCE AT JULY 31, 1995 1,000 $ 1,000
===== =======
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-6
<PAGE> 40
NATIONAL ENERGY RESOURCES, INC.
STATEMENT OF RETAINED EARNINGS
FOR THE PERIOD ENDED JULY 31, 1995

<TABLE>
<S> <C>
RETAINED EARNINGS - AUGUST 1, 1994 $ 0

ADD - NET INCOME FOR THE PERIOD ENDED JULY 31, 1995 (1,508)
---------
RETAINED EARNINGS - JULY 31, 1995 $ (1,508)
=========
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-7
<PAGE> 41
NATIONAL ENERGY RESOURCES, INC.
STATEMENT OF CASH FLOWS
FOR THE PERIOD ENDED JULY 31, 1995

<TABLE>
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME, PER INCOME STATEMENT $ (1,508)
ADD:
AMORTIZATION $ 708
INCREASE IN ACCOUNTS PAYABLE 10,319
INCREASE IN CURRENT LIABILITIES 800 11,827
---------- ----------
$ 10,319
NET CASH FLOW FROM OPERATING ACTIVITIES $ 10,319

CASH FLOWS FROM INVESTING ACTIVITIES:
LESS: CASH PAID - EQUIPMENT AND OTHER ASSETS $ 6,066
----------
NET CASH FLOW USED FOR INVESTING ACTIVITIES $ (6,066)

CASH FLOWS FROM FINANCING ACTIVITIES:
ADD:

INCREASE IN STOCKHOLDERS $ 14,217 $ 15,217
INCREASE IN COMMON STOCK 1,000 ----------
----------
DEDUCT: $ 19,050
INCREASE IN OTHER ASSETS $ 19,050 ----------
----------
NET CASH FLOW PROVIDED BY FINANCING ACTIVITIES $ (3,833)
-----------
INCREASE IN CASH $ 420
CASH AT THE BEGINNING OF THE YEAR 0
-----------
CASH AT THE END OF THE YEAR $ 420
===========
</TABLE>

SEE NOTES TO FINANCIAL STATEMENTS

F-8

<PAGE> 42
NATIONAL ENERGY RESOURCES, INC.
BALANCE SHEET
APRIL 30, 1996

ASSETS

<TABLE>
<S> <C> <C> <C>
CURRENT ASSETS
CASH $ 4,754
PETTY CASH 420
-------------
TOTAL CURRENT ASSETS $ 5,174

INTANGIBLE ASSETS
INTANGIBLE ASSETS $ 6,066
LESS-ACCUMULATED AMORTIZATION 1,618 4,448
------------ -------------
TOTAL INTANGIBLE ASSETS 4,448

OTHER ASSETS
DEFERRED ISSUE COSTS 24,721
-------------
TOTAL OTHER ASSETS 24,721
--------------
TOTAL ASSETS $ 34,343
==============

LIABILITIES

CURRENT LIABILITIES
ACCRUED INTEREST EXPENSE $ 1,781
-------------
TOTAL CURRENT LIABILITIES $1,781

LONG-TERM LIABILITIES
LOANS FROM STOCKHOLDERS 35,878
-------------
TOTAL LONG-TERM LIABILITIES 35,878

STOCKHOLDERS' EQUITY
COMMON STOCK 1,000
RETAINED EARNINGS - (DEFICIT) (4,316)
-------------
TOTAL STOCKHOLDERS' EQUITY (3,316)
--------------
TOTAL LIABILITIES/STOCKHOLDERS' EQUITY $ 34,343
==============
</TABLE>

UNAUDITED

F-9
<PAGE> 43
NATIONAL ENERGY RESOURCES, INC.
STATEMENT OF INCOME
NINE MONTHS ENDED APRIL 30, 1996

<TABLE>
<S> <C>
GENERAL/ADMINISTRATIVE EXPENSES - SCHEDULE A $ 2,808

----------------
OPERATING PROFIT (2,808)

NET LOSS $ (2,808)
===============
</TABLE>

UNAUDITED

F-10
<PAGE> 44
NATIONAL ENERGY RESOURCES, INC.
SUPPORTING SCHEDULES
NINE MONTHS ENDED APRIL 30, 1996

SCHEDULE A - GENERAL AND ADMINISTRATIVE

<TABLE>
<S> <C>
AMORTIZATION $ 910
INTEREST 1,790
STATE FILING FEE 108
-------------
TOTAL GENERAL AND ADMINISTRATIVE EXPENSE $ 2,808
=============

</TABLE>

UNAUDITED

F-11
<PAGE> 45
NATIONAL ENERGY RESOURCES, INC.
STATEMENT OF RETAINED EARNINGS
NINE MONTHS ENDED APRIL 30, 1996

<TABLE>
<S> <C>
RETAINED EARNINGS - AUGUST 1, 1995 $ (1,508)
ADD - NET LOSS FOR THE NINE MONTHS ENDED APRIL 30, 1996 (2,808)
-------------
RETAINED EARNINGS - APRIL 30, 1996 - (DEFICIT) $ (4,316)
=============
</TABLE>

UNAUDITED

F-12
<PAGE> 46
NATIONAL ENERGY RESOURCES, INC.
STATEMENT OF CASH FLOWS
FOR THE PERIOD ENDED APRIL 30, 1996

<TABLE>
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
NET LOSS, PER INCOME STATEMENT $ (2,808)
ADD:
AMORTIZATION $ 910
INCREASE IN CURRENT LIABILITIES 981 1,891
------------- ---------------
$ (917)
DEDUCT:
DECREASE IN ACCOUNTS PAYABLE $ 10,319 $ 10,319
------------- ---------------
NET CASH FLOW FROM OPERATING ACTIVITIES (11,236)

CASH FLOWS FROM FINANCING ACTIVITIES:
ADD:
INCREASE IN STOCKHOLDERS' LOANS $ 21,661 $ 21,661
------------- ---------------
DEDUCT:
INCREASE IN OTHER ASSETS $ 5,671 $ 5,671
------------- ---------------
NET CASH FLOW PROVIDED BY FINANCING ACTIVITIES $ 15 ,990
,990 ------------

INCREASE IN CASH $ 4,754
CASH AT THE BEGINNING OF THE YEAR 420

CASH AT THE END OF THE YEAR $ 5,174
=============
</TABLE>

UNAUDITED--

F-13
<PAGE> 47
NATIONAL ENERGY RESOURCES, INC.
(A Development Stage Company)
NOTES TO THE FINANCIAL STATEMENTS

NOTE A - FORMATION AND OPERATIONS OF THE COMPANY

National Energy Resources, Inc. (the Company) was incorporated under the laws of
the state of California on August 8, 1994. The Company is considered to be in
the development stage as defined in Financial Accounting Standard No. 7.
National Energy Resources, Inc. intends to be in the business of purchasing
producing oil and gas properties and the rights to a specified share of the
production revenues from the minerals in place.

NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting
Accounting records of the Company and financial statements are maintained and
prepared on the accrual basis.

Year End
The Company's year end for financial reporting and tax purposes is July 31.

Cash Equivalents
For financial statement purposes, with respect to the Statement of Cash Flows,
cash equivalents include time deposits and all highly liquid instruments with
original maturities of three months or less. The amount included on the
Company's Statement of Cash Flows is comprised exclusively of cash.

Income Taxes
The Company, with the consent of its shareholders, has elected to be taxed as
"C" corporation for Federal and State purposes. Federal and State taxes have
been accrued.

Deferred Issue Costs
Direct costs incurred to register and issue the secured notes are deferred and
amortized to interest expense over the lives of the loans using the actuarial
method.

Organizational Cost
Direct costs incurred to set up the Corporation are capitalized and amortized
over a sixty month period beginning January 1, 1995.

F-14
<PAGE> 48
NATIONAL ENERGY RESOURCES, INC.
(A Development Stage Company)
NOTES TO THE FINANCIAL STATEMENTS
(Continued)

NOTE C - STOCKHOLDERS' EQUITY

The Company is authorized to issue 1,000 shares of common stock at $1 par
value. On July 31, 1995 and April 30, 1996, there were 1,000 shares of common
stock issued and outstanding.

The holders of the common stock are entitled to one vote per share on all
matters to voted on by shareholders.

NOTE D - CONTRACT TO PURCHASE OIL AND GAS PROPERTIES

The Company has entered into a $430,000 contract with Blackjack oil and Gas,
Inc. for the purchase of six producing gas wells which have well-established
production histories and are operated by Blackjack. Both parties are bound by
the contract. The company plans to use the proceeds from the offering to
settle the obligation.

NOTE E - PROPOSED TRUST UNIT OFFERING

The Company intends to offer a total of 6,000 trust units in the principle
amount of $1,000 each. The trust units will bear a rate of return from 12%
to 14% annum, payable semiannually. The notes will be secured by the oil and
gas properties acquired with the proceeds of the offering and by the production
revenues. The trust units are designed to pay back the trust unitholders their
original investment in five years and may be terminated at any time after two
years from the closing date upon the payment to the trust unitholders of 100%
of their original investment.

The trust units are being offered on a "best-effort" basis. There is a
$500,000 minimum offering for the units per trust.

NOTE F - LOANS FROM OFFICERS/SHAREHOLDERS

Amounts due to officers/shareholders at July 31, 1995 and April 30, 1996 of
$19,050. and $35,878., bear interest at 8% per annum. Included in accrued
expenses is interest payable to officers/stockholders of $1781 at April 30,
1996. The officers/shareholders have agreed not to demand repayment of the
loans for the period of five years starting on August 8, 1994, the date of
inception.

F-15
<PAGE> 49
EXHIBIT A

April 17, 1996

National Energy Resources, Inc.
16130 Ventura Blvd., Suite 310
Encino, CA 91436

Gentlemen:

At your request, we have prepared an estimate of the proved producing reserves
and income attributable to these leasehold interests to be acquired by National
Energy Resources, Inc. as of October 1, 1996. The subject properties are
located in Oklahoma. The income data have been estimated using the Securities
and Exchange Commission ("S.E.C.") guidelines for future cost and price
parameters. The results of this study are summarized below.

S.E.C. CASE
Estimated Proved Producing Net Reserves and Income Data
Attributed to Certain Leasehold Interest to be Accquired by
National Energy Resources, Inc.
As of April 17, 1996

- --------------------------------------------------------------------------------
Proved Producing
<TABLE>
<S> <C>
Net Remaining Reserves
Gas MCF 1,743,808
Oil BBLS 5,821

Income Data
Future Gross Revenue $ 2,081,552
Deductions $ 648,837

Future Net Income (FNI) $ 1,432,717

Discounted FNI @ 10% $ 874,544

</TABLE>

All gas volumes are expressed in thousands of cubic feet (MCF) at the
temperature and pressure of the areas where the gas reserves are located.

The future gross revenue is before the deduction of production taxes.
The future net income is after deductions of operating expense and production
taxes. The deductions are based on current data and are comprised of normal
direct cost of operating the wells, which include ad valorem taxes and any
workover cost. The future gross income is before deductions of state and
federal income taxes. The discounted future net income is based on a discount
rate of 10 percent per annum.

A-1
<PAGE> 50
The proved producing reserves presented in this report comply with the
Securities and Exchange Commission's Regulation S-X Part 210.4-10 Sec. (a) as
clarified by the Commission's Staff Accounting Bulletin No. 40.

All the reserves in this report are "Proved Producing" reserves. Proved
producing reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological, engineering, and historical
production date demonstrate with reasonable certainty to be recoverable in the
future from the present producing reservoirs under existing conditions.

The relatively low weighted price of the natural gas for these properties
is due to the Bryan #1 well having 30.62% Nitrogen in its gas stream. This has
to be removed by processing through a plant. After deducting the Nitrogen, the
fuel gas to run the plant and shrinkage, the well head has a price of 0.70 per
MCF.

Blackjack Oil & Gas furnished us with gas prices in effect at January,
1996. In accordance with S.E.C. guidelines, the future gas prices used in
this report make no allowances for future gas price increases which may occur
as a result of inflation nor do they make any allowance for seasonal variations
in gas prices which are likely to cause future yearly average gas prices to be
somewhat higher than January, 1996 gas prices.

Operating costs for the leases and wells in this report are based on the
operating expenses provided by Blackjack Oil & Gas and include only those costs
directly applicable to the leases or wells. The current operating costs were
held constant throughout the life of the properties. This study does not
consider the salvage value of the lease equipment or the abandonment cost since
both are relatively insignificant and tend to offset each other for properties
located onshore.

The reserve estimates presented herein are based upon our study of the
subject properties; however, we have not made any field examination of the
properties. No consideration was given in this report to potential
environmental liabilities which may exist nor were any costs included for
potential liability to restore and clean up damages, if any, caused by past
operating practices. The ownership interest, prices, and other factual data
furnished us by Blackjack Oil & Gas in connection with this investigation were
accepted without independent verification.

The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually
recovered. Moreover, estimates of proved producing reserves may increase or
decrease as a result of future operations of the operator.

The future prices received by National Energy Resources for the sale of
its production may be higher or lower than the prices used in this report as
described above, and the operating costs and other costs relating to such
production may also increase or decrease from existing levels; however, such
possible changes in prices and costs were, in accordance with rules adopted by
the S.E.C., omitted from consideration in preparing this report.

A-2
<PAGE> 51
Neither Fred W. Elton or any of his employees have any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future cash inflows
for the subject properties.

Very truly yours,

By: /s/ F.W. ELTON
------------------------------
F. W. Elton
Petroleum Engineer

A-3
<PAGE> 52
TOTAL PROVED PRODUCING
ALL FORMATIONS
ALL WELLS
ALL FIELDS
VARIOUS COUNTIES, OK

ONE LINE SUMMARY BY INDIVIDUAL PROPERTY
RESERVES & ECONOMIC EVALUATION
PREPARED BY: F.W. ELTON

AS OF: 4/96

CASE LEASE SAND GROSS GROSS NET TOTAL NET NET TAXES BEFIT DISCOUNTED
NO NAME NAME OIL GAS OIL GAS SALES & OP ESP CASH FLOW CASH FLOW
- ---- ---------- ------- ------ --------- ----- ------- ------- --------- --------- ----------
MMBLS MMCF MMBLS MMCF M$ M$ M$ M$
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 BRYAN #1-6 TONKAWA 1,165.226 897.224 628.056 152.561 475.496 283.445

85 ENOCH #1 MORROW 226.590 174.474 279.159 94.206 184.953 131.045

86 ACTION #2 HOOVER 370.295 285.127 456.204 98.368 357.836 188.620

87 DAVIS #1-A PRUE 12.391 426.422 5.821 200.330 419.488 198.513 220.976 144.348

83 PHILLIPS MORROW 242.406 186.653 298.645 105.189 193.456 127.086
- ---------------------------- ------ --------- ----- --------- --------- -------- --------- --------
TOTAL PROVED PRODUCING 12.391 2,430.939 5.821 1,743.808 2,081.552 648.837 1,432.717 874.544
</TABLE>

A-4
<PAGE> 53
<TABLE>
<S> <C> <C>
EVALUATION ACTION2.1 EUREKA RUN DATE: 04-16-1996
PETROLEUM ECONOMICS SOFTWARE RUN TIME: 16:41:17
PACIFIC RESOURCES MANAGEMENT

AS OF DATE: MAR 96
NPV 5.0% 293.737 BFIT
NAME: ACTION2 NPV 10.0% 248.001 BFIT
FIELD: NPV 15.0% 214.259 BFIT
LOCATION: SEC 28-18N-4W/LOGAN CO NPV 20.0% 188.620 BFIT
FORMATION: NPV 25.0% 168.626 BFIT
OPERATOR: BLACKJACK OIL & GAS IRR LESS THAN 100% BFIT
PAYOUT MAY 96 BFIT
PI N/A BFIT

<CAPTION>
======== INTERESTS AND EFFECTIVE DATE ======= ========= PRICES ========= ============== GROSS RESERVES =============
COST OIL GAS COND PRODT DATE BEGINNING ENDING AVERAGE CUMULATIVE REMAINING ULTIMATE %REMAINING
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1.00000 0.77000 0.77000 0.77000 0.77000 MAY96 OIL 0.00 0.00 0.00 0.000 0.000 0.000 0.00 OIL
GAS 1.60 1.60 1.60 0.000 370.295 370.295 100.00 GAS
COND 0.00 0.00 0.00 0.000 0.000 0.000 0.00 COND
PRDT 0.00 0.00 0.00 0.000 0.000 0.000 0.00 PRDT

<CAPTION>
GROSS AVERAGE GROSS OIL NET OIL NET AVERAGE AVERAGE NET GAS NET NET TOTAL
YEAR WELLCOUNT OIL PRICE PRODUCTION PRODUCTION OIL SALES GOR GAS PRICE PRODUCTION GAS SALES REVENUE
========== = WELLS = == $/B == = MBBLS == = MBBLS == == M$ === = SCF/B = = $/MSCF = = MMSCF == == M$ === == M$ ===
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 1.000 0.000 0.000 0.000 0.000 0.000 1.600 34.027 54.433 54.443
1997 1.000 0.000 0.000 0.000 0.000 0.000 1.600 42.463 67.940 67.940
1998 1.000 0.000 0.000 0.000 0.000 0.000 1.600 35.263 56.420 56.420
1999 1.000 0.000 0.000 0.000 0.000 0.000 1.600 30.154 48.246 48.246
2000 1.000 0.000 0.000 0.000 0.000 0.000 1.600 26.340 42.144 42.144
2001 1.000 0.000 0.000 0.000 0.000 0.000 1.600 23.383 37.413 37.413
2002 1.000 0.000 0.000 0.000 0.000 0.000 1.600 21.024 33.638 33.638
2003 1.000 0.000 0.000 0.000 0.000 0.000 1.600 19.097 30.556 30.556
2004 1.000 0.000 0.000 0.000 0.000 0.000 1.600 17.494 27.991 27.991
2005 1.000 0.000 0.000 0.000 0.000 0.000 1.600 16.140 25.824 25.824
2006 1.000 0.000 0.000 0.000 0.000 0.000 1.600 14.980 23.968 23.968
2007(4 Mo) 1.000 0.000 0.000 0.000 0.000 0.000 1.600 4.763 7.621 7.621
2008 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 1.000 0.000 0.000 0.000 0.000 0.000 1.600 285.127 456.204 456.204
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 11.2 Yr 1.000 0.000 0.000 0.000 0.000 0.000 1.600 285.127 456.204 456.204

<CAPTION>
INPUT LOE NET NET TOTAL NET TOTAL NET LEASE NET TOTAL NET BFIT CUM BFIT BFIT CF CUM BFIT CF
YEAR -- WELL -- TOTAL LOE PROD TAX LOE+TAX REVENUE INVESTMENTS CASHFLOW CASHFLOW DISC 20.0% DISC 20.0%
========== =M$/WELLYR= === M$ == === M$ == === M$ == === M$ == ==== M$ === === M$ == == M$ == === M$ === === M$ ====
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 6.000 4.000 3.863 7.863 46.580 0.000 46.580 46.580 42.300 42.300
1997 6.000 6.000 4.820 10.820 57.120 0.000 57.120 103.700 44.666 86.967
1998 6.000 6.000 4.003 10.003 46.417 0.000 46.417 150.117 30.232 117.199
1999 6.000 6.000 3.423 9.423 38.823 0.000 38.823 188.940 21.064 138.263
2000 6.000 6.000 2.990 8.990 33.154 0.000 33.154 222.094 14.986 153.249
2001 6.000 6.000 2.654 8.654 28.759 0.000 28.759 250.852 10.831 164.079
2002 6.000 6.000 2.387 8.387 25.252 0.000 25.252 276.104 7.924 172.003
2003 6.000 6.000 2.168 8.168 22.388 0.000 22.388 298.492 5.853 177.856
2004 6.000 6.000 1.986 7.986 20.005 0.000 20.005 318.497 4.358 182.215
2005 6.000 6.000 1.832 7.832 17.991 0.000 17.991 336.488 3.266 185.480
2006 6.000 6.000 1.701 7.701 16.267 0.000 16.267 352.755 2.461 187.941
2007(4 Mo) 6.000 2.000 0.541 2.541 5.081 0.000 5.081 357.836 0.679 188.620
2008 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 6.000 66.000 32.368 98.368 357.836 0.000 357.836 357.836 188.620 188.620
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 11.2 Yr 6.000 66.000 32.368 98.368 357.836 0.000 357.836 357.836 188.620 188.620
</TABLE>

A-5
<PAGE> 54
<TABLE>
<S> <C> <C>
EVALUATION BRYAN.1 EUREKA RUN DATE: 04-16-1996
PETROLEUM ECONOMICS SOFTWARE RUN TIME: 16:39:25
PACIFIC RESOURCES MANAGEMENT

AS OF DATE: MAR96
NPV 5.0% 358.253 BFIT
NAME: BRYAN NPV 10.0% 283.445 BFIT
FIELD: CHAD NPV 15.0% 233.112 BFIT
LOCATION: SEC 6 20N 5E/PAWNEE CO NPV 20.0% 197.637 BFIT
FORMATION: TONKAWA NPV 25.0% 171.611 BFIT
OPERATOR: BLACKJACK OIL & GAS IRR LESS THAN 100% BFIT
PAYOUT MAY96 BFIT
PI N/A BFIT

<CAPTION>
======== INTERESTS AND EFFECTIVE DATE ======= ========= PRICES ========= ============== GROSS RESERVES =============
COST OIL GAS COND PRODT DATE BEGINNING ENDING AVERAGE CUMULATIVE REMAINING ULTIMATE %REMAINING
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1.00000 0.77000 0.77000 0.77000 0.77000 MAY96 OIL 0.00 0.00 0.00 0.000 0.000 0.000 0.00 OIL
GAS 0.70 0.70 0.70 0.000 1165.225 1165.225 100.00 GAS
COND 0.00 0.00 0.00 0.000 0.000 0.000 0.00 COND
PRDT 0.00 0.00 0.00 0.000 0.000 0.000 0.00 PRDT

<CAPTION>
GROSS AVERAGE GROSS OIL NET OIL NET AVERAGE AVERAGE NET GAS NET NET TOTAL
YEAR WELLCOUNT OIL PRICE PRODUCTION PRODUCTION OIL SALES GOR GAS PRICE PRODUCTION GAS SALES REVENUE
========== = WELLS = == $/B == = MBBLS == = MBBLS == == M$ === = SCF/B = = $/MSCF = = MMSCF == == M$ === == M$ ===
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 1.000 0.000 0.000 0.000 0.000 0.000 0.700 65.368 45.757 45.757
1997 1.000 0.000 0.000 0.000 0.000 0.000 0.700 90.049 63.034 63.034
1998 1.000 0.000 0.000 0.000 0.000 0.000 0.700 81.974 57.382 57.382
1999 1.000 0.000 0.000 0.000 0.000 0.000 0.700 75.228 52.660 52.660
2000 1.000 0.000 0.000 0.000 0.000 0.000 0.700 69.509 48.656 48.656
2001 1.000 0.000 0.000 0.000 0.000 0.000 0.700 64.598 45.219 45.219
2002 1.000 0.000 0.000 0.000 0.000 0.000 0.700 60.336 42.235 42.235
2003 1.000 0.000 0.000 0.000 0.000 0.000 0.700 56.601 39.621 39.621
2004 1.000 0.000 0.000 0.000 0.000 0.000 0.700 53.302 37.311 37.311
2005 1.000 0.000 0.000 0.000 0.000 0.000 0.700 50.367 35.257 35.257
2006 1.000 0.000 0.000 0.000 0.000 0.000 0.700 47.737 33.416 33.416
2007 1.000 0.000 0.000 0.000 0.000 0.000 0.700 45.369 31.759 31.759
2008 1.000 0.000 0.000 0.000 0.000 0.000 0.700 43.225 30.258 30.258
2009 1.000 0.000 0.000 0.000 0.000 0.000 0.700 41.274 28.892 28.892
2010 1.000 0.000 0.000 0.000 0.000 0.000 0.700 39.492 27.645 27.645
SUBTOTAL 1.000 0.000 0.000 0.000 0.000 0.000 0.700 884.429 619.101 619.101
REMAINING 1.000 0.000 0.000 0.000 0.000 0.000 0.700 12.794 8.956 8.956
TOT 15.2Yr 1.000 0.000 0.000 0.000 0.000 0.000 0.700 897.224 628.056 628.056

<CAPTION>
INPUT LOE NET NET TOTAL NET TOTAL NET LEASE NET TOTAL NET BFIT CUM BFIT BFIT CF CUM BFIT CF
YEAR -- WELL -- TOTAL LOE PROD TAX LOE+TAX REVENUE INVESTMENTS CASHFLOW CASHFLOW DISC 20.0% DISC 20.0%
========== =M$/WELLYR= === M$ == === M$ == === M$ == === M$ == ==== M$ === === M$ == == M$ == === M$ === === M$ ====
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 7.200 4.800 3.246 8.046 37.711 0.000 37.711 37.711 34.213 34.213
1997 7.200 7.200 4.472 11.672 51.362 0.000 51.362 89.073 40.096 74.309
1998 7.200 7.200 4.071 11.271 46.110 0.000 46.110 135.183 29.993 104.302
1999 7.200 7.200 3.736 10.936 41.723 0.000 41.723 176.907 22.614 126.915
2000 7.200 7.200 3.452 10.652 38.004 0.000 38.004 214.911 17.163 144.079
2001 7.200 7.200 3.208 10.408 34.810 0.000 34.810 249.721 13.100 157.178
2002 7.200 7.200 2.997 10.197 32.038 0.000 32.038 281.760 10.047 167.225
2003 7.200 7.200 2.811 10.011 29.610 0.000 29.610 311.369 7.737 174.962
2004 7.200 7.200 2.647 9.847 27.464 0.000 27.464 338.834 5.980 180.942
2005 7.200 7.200 2.501 9.701 25.555 0.000 25.555 364.389 4.637 185.579
2006 7.200 7.200 2.371 9.571 23.845 0.000 23.845 388.234 3.605 189.184
2007 7.200 7.200 2.253 9.453 22.305 0.000 22.305 410.539 2.810 191.994
2008 7.200 7.200 2.147 9.347 20.911 0.000 20.911 431.450 2.195 194.190
2009 7.200 7.200 2.050 9.250 19.642 0.000 19.642 451.092 1.718 195.908
2010 7.200 7.200 1.961 9.161 18.483 0.000 18.483 469.575 1.348 197.256
SUBTOTAL 7.200 105.600 43.925 149.525 469.575 0.000 469.575 469.575 197.256 197.256
REMAINING 7.200 2.400 0.635 3.035 5.920 0.000 5.920 475.496 0.381 197.637
TOT 15.2Yr 7.200 108.000 44.561 152.561 475.496 0.000 475.496 475.496 197.637 197.637
</TABLE>

A-6
<PAGE> 55
<TABLE>
<S> <C> <C>
EVALUATION DAVIS.1 EUREKA RUN DATE: 04-16-1996
PETROLEUM ECONOMICS SOFTWARE RUN TIME: 16:37:31
PACIFIC RESOURCES MANAGEMENT

AS OF DATE: MAR 96
NPV 5.0% 175.569 BFIT
NAME: DAVIS NPV 10.0% 144.348 BFIT
FIELD: EDMOND WEST NPV 15.0% 122.027 BFIT
LOCATION: SEC 22-14N-4W/OKLAHOMA CO NPV 20.0% 105.514 BFIT
FORMATION: NPV 25.0% 95.925 BFIT
OPERATOR: BLACKJACK OIL & GAS IRR LESS THAN 100% BFIT
PAYOUT MAY 96 BFIT
PI N/A BFIT

<CAPTION>
======== INTERESTS AND EFFECTIVE DATE ======= ========= PRICES ========= ============== GROSS RESERVES =============
COST OIL GAS COND PRODT DATE BEGINNING ENDING AVERAGE CUMULATIVE REMAINING ULTIMATE %REMAINING
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
0.75000 0.46980 0.46980 0.46980 0.46980 MAY96 OIL 17.00 17.00 17.00 0.000 12.391 12.391 100.00 OIL
GAS 1.60 1.60 1.60 0.000 426.416 426.416 100.00 GAS
COND 0.00 0.00 0.00 0.000 0.000 0.000 0.00 COND
PRDT 0.00 0.00 0.00 0.000 0.000 0.000 0.00 PRDT

<CAPTION>
GROSS AVERAGE GROSS OIL NET OIL NET AVERAGE AVERAGE NET GAS NET NET TOTAL
YEAR WELLCOUNT OIL PRICE PRODUCTION PRODUCTION OIL SALES GOR GAS PRICE PRODUCTION GAS SALES REVENUE
========== = WELLS = == $/B == = MBBLS == = MBBLS == == M$ === = SCF/B = = $/MSCF = = MMSCF == == M$ === == M$ ===
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 1.000 17.000 1.035 0.486 8.266 31558.615 1.600 15.345 24.552 32.817
1997 1.000 17.000 1.448 0.680 11.568 31606.814 1.600 21.508 34.413 45.981
1998 1.000 17.000 1.333 0.626 10.643 31839.168 1.600 19.933 31.983 42.536
1999 1.000 17.000 1.226 0.576 9.791 32246.189 1.600 18.573 29.717 39.508
2000 1.000 17.000 1.128 0.530 9.008 32811.340 1.600 17.386 27.818 36.827
2001 1.000 17.000 1.038 0.488 8.288 33523.340 1.600 16.343 26.148 34.436
2002 1.000 17.000 0.955 0.449 7.625 34374.785 1.600 15.417 24.667 32.292
2003 1.000 17.000 0.878 0.413 7.015 35361.223 1.600 14.591 23.345 30.360
2004 1.000 17.000 0.808 0.380 6.453 36480.910 1.600 13.849 22.158 28.611
2005 1.000 17.000 0.743 0.349 5.937 37733.789 1.600 13.178 21.085 27.022
2006 1.000 17.000 0.684 0.321 5.462 39121.074 1.600 12.570 20.112 25.574
2007 1.000 17.000 0.629 0.296 5.025 40646.332 1.600 12.015 19.224 24.249
2008(10Mo) 1.000 17.000 0.486 0.228 3.879 42171.043 1.600 9.623 15.397 19.276
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 1.000 17.000 12.391 5.821 98.960 34413.887 1.600 200.330 320.528 419.488
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 12.7 Yr 1.000 17.000 12.391 5.821 98.960 34413.887 1.600 200.330 320.528 419.488

<CAPTION>
INPUT LOE NET NET TOTAL NET TOTAL NET LEASE NET TOTAL NET BFIT CUM BFIT BFIT CF CUM BFIT CF
YEAR -- WELL -- TOTAL LOE PROD TAX LOE+TAX REVENUE INVESTMENTS CASHFLOW CASHFLOW DISC 20.0% DISC 20.0%
========== =M$/WELLYR= === M$ == === M$ == === M$ == === M$ == ==== M$ === === M$ == == M$ == === M$ === === M$ ====
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 18.000 9.000 2.328 11.328 21.489 0.000 21.489 21.489 19.496 19.496
1997 18.000 13.500 3.262 16.762 29.219 0.000 29.219 50.708 22.812 42.307
1998 18.000 13.500 3.018 16.518 26.018 0.000 26.018 76.726 16.926 59.234
1999 18.000 13.500 2.803 16.303 23.205 0.000 23.205 99.931 12.580 71.814
2000 18.000 13.500 2.613 16.113 20.714 0.000 20.714 120.645 9.358 81.172
2001 18.000 13.500 2.443 15.943 18.493 0.000 18.493 139.137 6.962 88.134
2002 18.000 13.500 2.291 15.791 16.501 0.000 16.501 155.638 5.177 93.311
2003 18.000 13.500 2.154 15.654 14.706 0.000 14.706 170.344 3.845 97.156
2004 18.000 13.500 2.030 15.530 13.081 0.000 13.081 183.425 2.850 100.006
2005 18.000 13.500 1.917 15.417 11.605 0.000 11.605 195.030 2.107 102.113
2006 18.000 13.500 1.814 15.314 10.259 0.000 10.259 205.289 1.552 103.665
2007 18.000 13.500 1.720 15.220 9.029 0.000 9.029 214.318 1.139 104.804
2008(10Mo) 18.000 11.250 1.368 12.618 6.658 0.000 6.658 220.976 0.710 105.514
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 18.000 168.750 29.763 198.513 220.976 0.000 220.976 220.976 105.514 105.514
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 12.7 Yr 18.000 168.750 29.763 198.513 220.976 0.000 220.976 220.976 105.514 105.514
</TABLE>

A-7
<PAGE> 56
<TABLE>
<S> <C> <C>
EVALUATION ENOCH.1 EUREKA RUN DATE: 04-16-1996
PETROLEUM ECONOMICS SOFTWARE RUN TIME: 16:30:23
PACIFIC RESOURCES MANAGEMENT

AS OF DATE: MAR 96
NPV 5.0% 153.755 BFIT
NAME: ENOCH NPV 10.0% 131.045 BFIT
FIELD: WATONGA-CHICKASHA NPV 15.0% 114.009 BFIT
LOCATION: SEC 31-17N-10W/BLAINE CO NPV 20.0% 100.883 BFIT
FORMATION: NPV 25.0% 90.531 BFIT
OPERATOR: BLACKJACK OIL & GAS IRR LESS THAN 100% BFIT
PAYOUT MAY 96 BFIT
PI N/A BFIT

<CAPTION>
======== INTERESTS AND EFFECTIVE DATE ======= ========= PRICES ========= ============== GROSS RESERVES =============
COST OIL GAS COND PRODT DATE BEGINNING ENDING AVERAGE CUMULATIVE REMAINING ULTIMATE %REMAINING
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1.00000 0.77000 0.77000 0.77000 0.77000 MAY96 OIL 0.00 0.00 0.00 0.000 0.000 0.000 0.00 OIL
GAS 1.60 1.60 1.60 0.000 226.590 226.590 100.00 GAS
COND 0.00 0.00 0.00 0.000 0.000 0.000 0.00 COND
PRDT 0.00 0.00 0.00 0.000 0.000 0.000 0.00 PRDT

<CAPTION>
GROSS AVERAGE GROSS OIL NET OIL NET AVERAGE AVERAGE NET GAS NET NET TOTAL
YEAR WELLCOUNT OIL PRICE PRODUCTION PRODUCTION OIL SALES GOR GAS PRICE PRODUCTION GAS SALES REVENUE
========== = WELLS = == $/B == = MBBLS == = MBBLS == == M$ === = SCF/B = = $/MSCF = = MMSCF == == M$ === == M$ ===
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 1.000 0.000 0.000 0.000 0.000 0.000 1.600 20.121 32.194 32.194
1997 1.000 0.000 0.000 0.000 0.000 0.000 1.600 25.812 41.300 41.300
1998 1.000 0.000 0.000 0.000 0.000 0.000 1.600 21.957 35.131 35.131
1999 1.000 0.000 0.000 0.000 0.000 0.000 1.600 19.105 30.568 30.568
2000 1.000 0.000 0.000 0.000 0.000 0.000 1.600 16.910 27.055 27.055
2001 1.000 0.000 0.000 0.000 0.000 0.000 1.600 15.167 24.267 24.267
2002 1.000 0.000 0.000 0.000 0.000 0.000 1.600 13.750 22.000 22.000
2003 1.000 0.000 0.000 0.000 0.000 0.000 1.600 12.576 20.121 20.121
2004 1.000 0.000 0.000 0.000 0.000 0.000 1.600 11.586 18.538 18.538
2005 1.000 0.000 0.000 0.000 0.000 0.000 1.600 10.741 17.186 17.186
2006(8 Mo) 1.000 0.000 0.000 0.000 0.000 0.000 1.600 6.749 10.798 10.798
2007 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2008 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 1.000 0.000 0.000 0.000 0.000 0.000 1.600 174.474 279.159 279.159
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 10.5 Yr 1.000 0.000 0.000 0.000 0.000 0.000 1.600 174.474 279.159 279.159

<CAPTION>
INPUT LOE NET NET TOTAL NET TOTAL NET LEASE NET TOTAL NET BFIT CUM BFIT BFIT CF CUM BFIT CF
YEAR -- WELL -- TOTAL LOE PROD TAX LOE+TAX REVENUE INVESTMENTS CASHFLOW CASHFLOW DISC 20.0% DISC 20.0%
========== =M$/WELLYR= === M$ == === M$ == === M$ == === M$ == ==== M$ === === M$ == == M$ == === M$ === === M$ ====
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 7.200 4.800 2.284 7.084 25.110 0.000 25.110 25.110 22.799 22.799
1997 7.200 7.200 2.930 10.130 31.169 0.000 31.169 56.279 24.370 47.170
1998 7.200 7.200 2.493 9.693 25.439 0.000 25.439 81.718 16.569 63.738
1999 7.200 7.200 2.169 9.369 21.199 0.000 21.199 102.917 11.503 75.241
2000 7.200 7.200 1.920 9.120 17.936 0.000 17.936 120.853 8.109 83.350
2001 7.200 7.200 1.722 8.922 15.345 0.000 15.345 136.198 5.781 89.130
2002 7.200 7.200 1.561 8.761 13.240 0.000 13.240 149.438 4.156 93.286
2003 7.200 7.200 1.428 8.628 11.494 0.000 11.494 160.931 3.006 96.292
2004 7.200 7.200 1.315 8.515 10.023 0.000 10.023 170.954 2.184 98.477
2005 7.200 7.200 1.219 8.419 8.766 0.000 8.766 179.720 1.592 100.069
2006(8 Mo) 7.200 4.800 0.766 5.566 5.232 0.000 5.232 184.953 0.815 100.883
2007 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2008 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 7.200 84.000 21.189 105.189 193.456 0.000 193.456 193.456 93.017 93.017
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 11.8 Yr 7.200 84.000 21.189 105.189 193.456 0.000 193.456 193.456 93.017 93.017
</TABLE>

A-8
<PAGE> 57
<TABLE>
<S> <C> <C>
EVALUATION PHILLIPS.1 EUREKA RUN DATE: 04-19-1996
PETROLEUM ECONOMICS SOFTWARE RUN TIME: 13:50:56
PACIFIC RESOURCES MANAGEMENT

AS OF DATE: MAR 96
NPV 5.0% 154.267 BFIT
NAME: PHILLIPS #1 NPV 10.0% 127.086 BFIT
FIELD: MOCANE-LAVERNE NPV 15.0% 107.537 BFIT
LOCATION: SEC 13-24N-24W/ELLIS CO., OK NPV 20.0% 93.017 BFIT
FORMATION: NPV 25.0% 81.922 BFIT
OPERATOR: BLACKJACK OIL & GAS, INC. IRR LESS THAN 100% BFIT
PAYOUT MAY 96 BFIT
PI N/A BFIT

<CAPTION>
======== INTERESTS AND EFFECTIVE DATE ======= ========= PRICES ========= ============== GROSS RESERVES =============
COST OIL GAS COND PRODT DATE BEGINNING ENDING AVERAGE CUMULATIVE REMAINING ULTIMATE %REMAINING
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1.00000 0.77000 0.77000 0.77000 0.77000 MAY96 OIL 0.00 0.00 0.00 0.000 0.000 0.000 0.00 OIL
GAS 1.60 1.60 1.60 0.000 242.406 242.406 100.00 GAS
COND 0.00 0.00 0.00 0.000 0.000 0.000 0.00 COND
PRDT 0.00 0.00 0.00 0.000 0.000 0.000 0.00 PRDT

<CAPTION>
GROSS AVERAGE GROSS OIL NET OIL NET AVERAGE AVERAGE NET GAS NET NET TOTAL
YEAR WELLCOUNT OIL PRICE PRODUCTION PRODUCTION OIL SALES GOR GAS PRICE PRODUCTION GAS SALES REVENUE
========== = WELLS = == $/B == = MBBLS == = MBBLS == == M$ === = SCF/B = = $/MSCF = = MMSCF == == M$ === == M$ ===
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 1.000 0.000 0.000 0.000 0.000 0.000 1.600 16.045 25.672 25.672
1997 1.000 0.000 0.000 0.000 0.000 0.000 1.600 22.103 35.365 35.365
1998 1.000 0.000 0.000 0.000 0.000 0.000 1.600 20.121 32.193 32.193
1999 1.000 0.000 0.000 0.000 0.000 0.000 1.600 18.465 29.544 29.544
2000 1.000 0.000 0.000 0.000 0.000 0.000 1.600 17.061 27.298 27.298
2001 1.000 0.000 0.000 0.000 0.000 0.000 1.600 15.856 25.369 25.369
2002 1.000 0.000 0.000 0.000 0.000 0.000 1.600 14.810 23.695 23.695
2003 1.000 0.000 0.000 0.000 0.000 0.000 1.600 13.893 22.229 22.229
2004 1.000 0.000 0.000 0.000 0.000 0.000 1.600 13.083 20.933 20.933
2005 1.000 0.000 0.000 0.000 0.000 0.000 1.600 12.363 19.780 19.780
2006 1.000 0.000 0.000 0.000 0.000 0.000 1.600 11.717 18.748 18.748
2007(12 Mo) 1.000 0.000 0.000 0.000 0.000 0.000 1.600 11.136 17.818 17.818
2008 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 1.000 0.000 0.000 0.000 0.000 0.000 1.600 186.653 298.645 298.645
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 11.8 Yr 1.000 0.000 0.000 0.000 0.000 0.000 1.600 186.653 298.645 298.645

<CAPTION>
INPUT LOE NET NET TOTAL NET TOTAL NET LEASE NET TOTAL NET BFIT CUM BFIT BFIT CF CUM BFIT CF
YEAR -- WELL -- TOTAL LOE PROD TAX LOE+TAX REVENUE INVESTMENTS CASHFLOW CASHFLOW DISC 20.0% DISC 20.0%
========== =M$/WELLYR= === M$ == === M$ == === M$ == === M$ == ==== M$ === === M$ == == M$ == === M$ === === M$ ====
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1996 7.200 4.800 1.821 6.621 19.050 0.000 19.050 19.050 17.285 17.285
1997 7.200 7.200 2.509 9.709 25.656 0.000 25.656 44.706 20.032 37.317
1998 7.200 7.200 2.284 9.484 22.709 0.000 22.709 67.415 14.775 52.092
1999 7.200 7.200 2.096 9.296 20.248 0.000 20.248 87.663 10.977 63.068
2000 7.200 7.200 1.937 9.137 18.161 0.000 18.161 105.824 8.204 71.272
2001 7.200 7.200 1.800 9.000 16.369 0.000 16.369 122.194 6.162 77.434
2002 7.200 7.200 1.681 8.881 14.814 0.000 14.814 137.008 4.647 82.080
2003 7.200 7.200 1.577 8.777 13.452 0.000 13.452 150.460 3.516 85.596
2004 7.200 7.200 1.485 8.685 12.248 0.000 12.248 162.708 2.668 88.264
2005 7.200 7.200 1.403 8.603 11.177 0.000 11.177 173.885 2.029 90,292
2006 7.200 7.200 1.330 8.530 10.218 0.000 10.218 184.102 1.545 91.838
2007(12 Mo) 7.200 7.200 1.264 8.464 9.354 0.000 9.354 193.456 1.179 93.017
2008 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2009 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2010 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
SUBTOTAL 7.200 84.000 21.189 105.189 193.456 0.000 193,456 193.456 93.017 93.017
REMAINING 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
TOT 11.8 Yr 7.200 84.000 21.189 105.189 193.456 0.000 193.456 193.456 93.017 93.017
</TABLE>

A-9
<PAGE> 58

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

No person has been authorized to give any
information or to make any representations other
than those contained in this Prospectus, and, if
given or made, such information or representations
must not be relied upon as having been authorized.
This Prospectus does not constitute an offer to
sell or the solicitation of an offer to buy any
securities other than the securities to which it
relates or any offer to sell or the solicitation
of an offer to buy such securities in any
circumstances in which such offer or solicitation
is unlawful. Neither the delivery of this
Prospectus nor any sale made hereunder shall,
under any circumstances, create any implication
that there has been no change in the affairs of
the Trust since the date hereof or imply that the
information contained herein is correct as of any
time subsequent to its date.
----------------------

Until ____________, 1996 (25 days after
the date of this Prospectus), all dealers
effecting transaction in the Trust Units, whether
or not participating in this distribution, may be
required to deliver a Prospectus. This is in
addition to the obligation of the dealers to
deliver a Prospectus when acting as underwriters
and with respect to their unsold allotment or
subscriptions.

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

500 TRUST UNITS

NATIONAL ENERGY RESOURCES
TRUST-A

P R O S P E C T U S

===================================================
<PAGE> 59
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

<TABLE>
<S> <C> <C>
13. EXPENSES OF ISSUANCE AND DISTRIBUTION(1).

SEC Filing Fees . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,068.97
Escrow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,700.00
Printing and Engraving . . . . . . . . . . . . . . . . . . . . . . 15,000.00
Legal Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,500.00
Accounting Fees . . . . . . . . . . . . . . . . . . . . . . . . . 3,500.00
Miscellaneous Fees . . . . . . . . . . . . . . . . . . . . . . . . 3,750.00
----------

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 54,518.97
===========
</TABLE>

____________
(1) All amounts are estimated except SEC filing fees.

14. INDEMNIFICATION OF OFFICERS AND DIRECTORS.

California Corporations Laws provide that a director, officer,
employee or agent of the Corporation may be indemnified against suit or other
proceeding whether it were civil, criminal, administrative or investigative if
he becomes a party to said lawsuit or proceeding by reason of the fact that he
is a director, officer, employee or agent of the corporation. The compensation
for indemnification includes judgments, fines and amounts paid in settlement
actual and reasonably incurred by him in connection with such action, suit or
proceeding if he acted in good faith and in a manner he reasonably believed to
be in or not opposed to the best interest of the corporation.

However, no indemnification shall be made in respect of any claim,
issue or matter as to which such person shall have been judged liable for
negligence or misconduct in the performance of his duty to the corporation,
unless the court in which the action or suit is brought shall determine that
despite his liability but in view of all the circumstances of the case, such
person is fairly and reasonably entitled to be indemnified for expenses such
court shall deem proper.

The By-Laws of the corporation outline the conditions under which any
director or officer of the registrant may be indemnified. The By-laws provide
that to the extent and in the manner permitted by the laws of the State of
California, the corporation shall indemnify any person who was or is a party or
is threatened to be made a party to any threatened, pending or completed
action, suit or proceeding, whether civil, criminal, administrative or
investigative, other than an action by or in the right of the corporation, by
reason of the fact that such person is or was a director, officer, employee or
agent of the corporation, or is or was serving at the request of the
corporation as a director, officer, employee or agent of another corporation,
partnership, joint venture, trust or other enterprise against expenses,
including attorneys' fees, judgments, fines and amounts paid in settlement.

15. RECENT SALES OF UNREGISTERED SECURITIES.

None.

II-1
<PAGE> 60
16. EXHIBITS.

<TABLE>
<CAPTION>
NUMBER DESCRIPTION OF EXHIBIT
- ------ ----------------------
<S> <C>
3. (i) National Energy Articles of Incorporation

(ii) National Energy By-Laws

4. Trust Agreement of National Energy Resources Trust-A (previously filed)

5. Legal Opinion of Robertson & Williams, Inc.*

8. Tax Opinion of Robertson & Williams, Inc.*

10. (i) Conveyance of Production Payment (previously filed)

(ii) Form Operating Agreement

(iii) Letter of Intent for Property Purchase

23. (i) Consent of Robertson & Williams, Inc.

(ii) Consent of Museck & Museck

(iii) Consent of F.W. Elton, Inc.
</TABLE>

* To be filed by Amendment.

17. UNDERTAKINGS.

1. The undersigned registrant hereby undertakes:

(a) To file, during any period in which offers or sales are
being made, a post-effective amendment to this registration statement:

(1) To include any prospectus required by Section
10(a)(3) of the Securities Act of 1933;

(2) To reflect in the prospectus any facts or events
arising after the effective date of the registration statement
(or the most recent post-effective amendment thereof) which,
individually or in the aggregate, represent a fundamental
change in the information set forth in the registration
statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total dollar
value of securities offered would not exceed that which was
registered) and any deviation from the low or high end of the
estimated maximum offering range may be reflected in the form
of prospectus filed with the Commission pursuant to Rule
424(b) (Section 230.424)(b) of this chapter) if, in the
aggregate, the changes in volume and price represent no more
than a 20% change in the maximum aggregate offering price set
forth in the "Calculation of Registration Fee" table in the
effective registration statement.

(3) To include any material information with respect
to the plan of distribution not previously disclosed in the
registration statement or any material change to such
information in the registration statement.

II-2
<PAGE> 61
2. For the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed to
be a new registration statement relating to the securities offered therein, and
the offering of the securities at that time shall be deemed to be the initial
bona fide offering.

3. To remove from registration by means of a post-effective
amendment any of the securities being registered which remain unsold at the
termination of the offering.

4. Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of the registrant pursuant to the foregoing provisions or otherwise,
the registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as expressed
in the Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or controlling
person of the registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant will, unless in
the opinion of counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Securities
Act and will be governed by the final adjudication of such issue.

5. The registrant will not identify to any third party any
prospects which will go into or are likely to be placed into the investment
program or are representative of prospects which may be placed into the
program, whether such third party is a selling dealer or other party involved
with making or directing investment decisions regarding the purchase of Trust
Units, except to the extent such prospects have been identified in the
prospectus, prospectus supplement or amendment thereto.

6. To the extent a review of prospects or lease inventory is
permitted to third parties, it will be:

(a) only incidental to an underwriter's due diligence
examination;

(b) no reference to any specific property (unless such
property is described in the prospectus, prospectus supplement or an
amendment) will appear in any analysis or report on the program
prepared by such third party; and

(c) any third party prior to receiving permission to
examine properties will agree to the above conditions, and the
registrant will file a copy of such agreement(s) as exhibit(s) to the
registration statement.

7. No prospective investors or their representatives will be
permitted to examine any prospects or reserve, inventory, or other data related
thereto which is not described in the prospectus, prospectus supplement or
amendment thereto.

8. The registrant will send to each investor at least on an
annual basis a detailed statement of any transaction by the Trust(s) with the
trustee(s) or affiliates of such trustee(s), and of fees, commissions,
compensation and other benefits paid or accrued to the trustee(s) for the
fiscal year completed, showing the amount paid or accrued to each recipient and
the services performed.

9. An annual report on Form 10-K will be filed at the conclusion
of the fiscal year following the year in which the registration statement is
declared effective.

10. A Form 8-K or final SR to reflect the expenditure of the
proceeds of the offering will be filed.

11. The prospectus will be supplemented at the close of formation
of each Trust to state the number of participants in that Trust, the amount of
Trust Units sold therein, the cumulative amount sold under all Trusts formed
under the subject registration statement, the amount of Trust Units to be
offered in the next Trust to be formed and in succeeding Trusts to be formed
under the registration statement.

12. Any unsold Trust Units will be deregistered upon termination
of the offering.

II-3
<PAGE> 62
13. National Energy hereby undertakes to provide the Trustee at
the closing instructions as to the issuance of trust certificates in such
denominations as required to permit prompt delivery to each purchaser.

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this registration statement to be signed on its
behalf by the undersigned, thereto duly authorized, in the City of Woodland
Hills, State of California on June 11, 1996.

(Registrant) NATIONAL ENERGY RESOURCES TRUST SERIES A
THROUGH L

By: NATIONAL ENERGY RESOURCES, INC..
Sponsor

By: /s/ Marshall J. Field
-----------------------------------
Marshall J. Field

(Signature and Title ) President, Chief
Financial Officer and
Director

II-4
<PAGE> 63
INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
3.(i) National Energy Articles of Incorporation

(ii) National Energy By-Laws

4. Trust Agreement of National Energy Resources Trust-A (previously filed)

5. Legal Opinion of Robertson & Williams, Inc.*

8. Tax Opinion of Robertson & Williams, Inc.*

10.(i) Conveyance of Production Payment (previously filed)

(ii) Form Operating Agreement

(iii) Letter of Intent for Property Purchase

23.(i) Consent of Robertson & Williams, Inc.

(ii) Consent of Museck & Museck

(iii) Consent of F.W. Elton, Inc.

</TABLE>

* To be filed by Amendment.

<PAGE> 1

State of California

SECRETARY OF STATE'S OFFICE

CORPORATION DIVISION

I, TONY MILLER, Acting Secretary of State of the State of California,
hereby certify:

That the annexed transcript has been compared with the corporate
record on file in this office, of which it purports to be a copy, and that same
is full, true and correct.

IN WITNESS WHEREOF, I execute this
certificate and affix the Great
Seal of the State of California this

AUG 8 1994
-----------

/s/ TONY MILLER
[SEAL] Acting Secretary of State

<PAGE> 2
ENDORSED
FILED
in the office of the Secretary of State
of the State of California

AUG 8 - 1994

TONY MILLER, Acting Secretary of State

ARTICLES OF INCORPORATION

NATIONAL ENERGY RESOURCES, INC.

The name of this corporation is:

NATIONAL ENERGY RESOURCES, INC.

The purpose of this corporation is to engage in any lawful act or
activity for which a corporation may be organized under the General Corporation
law of California, other than the banking business, the trust company business,
or the practice of a profession permitted to be incorporated by the California
Corporation's Code.

III

The name and address in the State of California for the
corporation's initial agent for service of process is:

MARSHALL J. FIELD
1875 CENTURY PARK EAST, SUITE 3100
LOS ANGELES, CA 90067

This corporation is authorized to issue only one class of stock, and
the total number of shares which this corporation is authorized to issue is ten
thousand (10,000) shares of no par value.

The liability of the directors of the corporation for monetary damages
shall be eliminated to the fullest extent permissible under California law.

ENDORSED
FILED
in the office of the Secretary of State
of the State of California

AUG 8 - 1994

TONY MILLER, Acting Secretary of State

<PAGE> 3

The corporation is authorized to provide indemnification of agents (as
defined in Section 317 of the Corporations Code) for breach of duty to the
corporation and its stockholders through bylaw provisions of through agreements
with the agents, or both, in excess of the indemnification otherwise permitted
by Section 317 of the Corporations Code, subject to the limits on such excess
indemnification set forth in Section 204 of the Corporations Code.

Dated: August 5, 1994

/s/ Walter Weiss
----------------------------
WALTER WEISS, Incorporator

I HEREBY DECLARE that I am the person who executed the foregoing
Articles of Incorporaton, which execution is my act and deed.

/s/ Walter Weiss
----------------------------
WALTER WEISS, Incorporator

articles

<PAGE> 1

BYLAWS OF

NATIONAL ENERGY RESOURCES, INC.

(A California Corporation)

ARTICLE I
SHAREHOLDERS' MEETINGS

Section 1. TIME. An annual meeting for the election of directors and for
the transaction of any other proper business and any special meeting shall be
held on the date and at the time as the Board of Directors shall from time to
time fix.

Time of Meeting: o'clock .M.
Date of Meeting: The day of

Section 2. PLACE. Annual meetings and special meetings shall be held at
such place, within or without the State of California, as the Directors may,
from time to time, fix. Whenever the Directors shall fail to fix such place,
the meetings shall be held at the principal executive office of the
corporation.

Section 3. CALL. Annual meetings may be called by the Directors, by the
Chairman of the Board, if any, Vice Chairman of the Board, if any, the
President, if any, the Secretary, or by any officer instructed by the
Directors to call the meeting. Special meetings may be called in like manner
and by the holders of shares entitled to cast not less than ten percent of the
votes at the meeting being called.

Section 4. NOTICE. Written notice stating the place, day and hour of each
meeting, and, in the case of a special meeting, the general nature of the
business to be transacted or, in the case of an Annual Meeting, those matters
which the Board of Directors, at the time of mailing of the notice, intends to
present for action by the shareholders, shall by given not less than ten days
(or not less than any such other minimum period of days as may be prescribed by
the General Corporation Law) or more than sixty days (or more than any such
maximum period of days as may be prescribed by the General Corporation Law)
before the date of the meeting, by mail, personally, or by other means of
written communication, charges prepaid by or at the direction of the Directors,
the President, if any, the Secretary or the officer or persons calling the
meeting, addressed to each shareholder at his address appearing on the books of
the corporation or given by him to the corporation for the purpose of notice,
or, if no such address appears or is given, at the place where the principal
executive office of the corporation is located or by publication at least
once in a newspaper of general circulation in the county in which the said
principal executive office is located.

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Such notice shall be deemed to be delivered when deposited in the
United States mail with first class postage therein prepaid, or sent by other
means of written communication addressed to the shareholder at his address as
it appears on the stock transfer books of the corporation. The notice of any
meeting at which directors are to be elected include the names of nominees
intended at the time of notice to be presented by management for election. At
an annual meeting of shareholders, any matter relating to the affairs of the
corporation, whether or not stated in the notice of the meeting, may be brought
up for action except matters which the General Corporation Law requires to be
stated in the notice of the meeting. The notice of any annual or special meeting
shall also include, or be accompanied by, any additional statements,
information, or documents prescribed by the General Corporation Law. When a
meeting is adjourned to another time or place, notice of the adjourned meeting
need not be given if the time and place thereof are announce at the meeting at
which the adjournment is taken; provided that, if after the adjournment a new
record date is fixed for the adjourned meeting, a notice of the adjourned
meeting shall be given to each shareholder. At the adjourned meeting, the
corporation may transact any business which might have been transacted at the
original meeting.

Section 5. CONSENT. The transaction of any meeting, however called and
noticed, and wherever held, shall be as valid as though had a meeting duly held
after regular call and notice, if a quorum is present and if, either before or
after the meeting, each of the shareholders or his proxy signs a written waiver
of notice or a consent to the holding of the meeting or an approval of the
minutes thereof. All such waivers, consents and approvals shall be filed with
the corporate records or made a part of the minutes of the meeting. Attendance
of a person at a meeting constitutes a waiver of notice of such meeting, except
when the person objects, at the beginning of the meeting, to the transaction of
any business because the meeting is not lawfully called or convened and except
that attendance at a meeting shall not constitute a waiver of any right to
object to the consideration of matters required by the General Corporation Law
to be included in the notice if such objection is expressly made at the
meeting. Except as otherwise provided in subdivision (f) of Section 601 of the
General Corporation Law, neither the business to be transacted at nor the
purpose of any regular or special meeting need be specified in any written
waiver of notice.

Section 6. CONDUCT OF MEETING. Meetings of the shareholders shall be
presided over by one of the following officers in the order of seniority and if
present and acting -- the Chairman of the Board, if any, the Vice-Chairman of
the Board, if any, the President, if any, a Vice-President, or, if none of the
foregoing is in office and present and acting, by a chairman to be chosen by
the shareholders. The Secretary of the corporation, or in his absence, an
Assistant Secretary, shall

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act as secretary of every meeting, but, if neither the Secretary nor an
Assistant Secretary is present, the Chairman of the meeting shall appoint a
secretary of the meeting.

Section 7. PROXY REPRESENTATION. Every shareholder may authorize another
person or persons to act as his proxy at a meeting or by written action. No
proxy shall be valid the expiration of eleven months from the date of its
execution unless otherwise provided in the proxy. Every proxy shall be
revocable at the pleasure of the person executing it prior to the vote or
written action pursuant thereto, except as otherwise provided by the General
Corporation Law. As used herein, a proxy shall be deemed to mean a written
authorization signed by a shareholder or a shareholder's attorney in fact
giving another person or persons power to vote or consent in writing with
respect to the shares of such shareholder, and "Signed" as used herein shall be
deemed to me an the placing of such shareholder's name on the proxy, whether by
manual signature, typewriting, telegraphic transmission or otherwise by such
shareholder or such shareholder's attorney in fact. Where applicable, the form
of any proxy shall comply with the provisions of Section 604 of the General
Corporation Law.

Section 8. INSPECTORS - APPOINTMENT. In advance of any meeting, the
Board of Directors may appoint inspectors of election to act at the meeting and
any adjournment thereof. If inspectors of election are not so appointed, or, if
any persons so appointed fail to appear or refuse to act, the Chairman of any
meeting of shareholders may, and on the request of any shareholder or a
shareholder's proxy shall, appoint inspectors of election, or persons to
replace any of those who so fail or refuse, at the meeting. The number of
inspectors shall be either one or three. If appointed at a meeting on the
request of one or more shareholders or proxies, the majority of shares
represented shall determine whether one or three inspectors are to be
appointed.

The inspectors of election shall determine the number of shares
outstanding and the voting power of each, the shares represented at the
meeting, the existence of a quorum, the authenticity, validity, and effect of
proxies, receive votes, ballots, if any, or consents, hear and determine all
challenges and questions in any way arising in connection with the right to
vote, count and tabulate all votes or consents, determine when the polls shall
close, determine the result, and do such acts as may be proper to conduct the
election or vote with fairness to all shareholders. If there are three
inspectors of election, the decision, act, or certificate of a majority shall
be effective in ail respects as the decision,

Section 9. SUBSIDIARY CORPORATIONS. Shares of this corporation owned
by a subsidiary shall not be entitled to vote on any matter. A subsidiary for
these purposes is

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defined as a corporation, the shares of which possessing more than 25% of the
total combined voting power of all classes of shares entitled to vote, are
owned directly or indirectly through one or more subsidiaries.

Section 10. QUORUM; VOTE; WRITTEN CONSENT. The holders of a majority of
the voting shares shall constitute a quorum at a meeting of shareholders for
the transaction of any business. The shareholders present at a duly called or
held meeting at which a quorum is present may continue to do business until
adjournment notwithstanding the withdrawal of enough shareholders to leave less
than a quorum if any action taken, other than adjournment, is approved by at
least a majority of the shares required to constitute a quorum. In the absence
of a quorum, any meeting of shareholders may be adjourned from time to time by
the vote of a majority of the shares represented thereat, but no other business
may be transacted except as hereinbefore provided.

In the election of directors, a plurality of the votes cast shall
elect. No shareholder shall be entitled to exercise the right of cumulative
voting at a meeting for the election of directors unless the candidate's name
or the candidates' names have been placed in nomination prior to the voting and
the shareholder has given notice at the meeting prior to the voting of the
shareholder's intention to cumulate the shareholder's votes. If any one
shareholder has given such notice, all shareholders may cumulate their votes
for such candidates in nomination.

Except As otherwise provided by the General Corporation Law, the
Articles of Incorporation or these Bylaws, any action required or permitted to
be taken at a meeting at which a quorum is present shall be authorized by the
affirmative vote of a majority of the shares represented at the meeting.

Except in the election of directors by written consent in lieu of a
meeting, and except as may otherwise be provided by the General Corporation
Law, the Articles of Incorporation or these Bylaws, any action which may be
taken at any annual or special meeting may be taken without a meeting and
without prior notice, if a consent in writing, setting forth the action so
taken, shall be signed by holders of shares having not less than the minimum
number of votes that would be necessary to authorize or take such action at a
meeting at which all shares entitled to vote thereon were present and voted.
Directors may not be elected by written consent except by unanimous written
consent of all shares entitled to vote for the election of directors. Notice of
any shareholder approval pursuant to Section 310, 317, 1201 or 2007 without a
meeting by less than unanimous written consent shall be given at least ten days
before the consummation of the action authorized by such approval, and prompt
notice shall be given of the taking of any other corporate action approved by
shareholders without a meeting by less than unanimous written

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consent to those shareholders entitled to vote who have not consented in
writing.

Section 11. BALLOT. Elections of directors at a meeting need not be by
ballot unless a shareholder demands election by ballot at the election and
before the voting begins. In all other matters, voting need not be by ballot.

Section 12. SHAREHOLDERS' AGREEMENTS. Notwithstanding the above
provisions in the event this corporation elects to become a close corporation,
an agreement between two or more shareholders thereof, if in writing and signed
by the parties thereof, may provide that in exercising any voting rights the
shares held by them shall be voted as provided therein or in Section 706, and
may otherwise modify these provisions as to shareholders' meetings and actions.

ARTICLE II
BOARD OF DIRECTORS

Section 1. FUNCTIONS. The business and affairs of the corporation shall
be managed and all corporate powers shall be exercised by or under the
direction of its Board of Directors. The Board of Directors may delegate the
management of the day-to-day operation of the business of the corporation to a
management company or other person, provided that the business and affairs of
the corporation shall be managed and all corporate powers shall be exercised
under the ultimate:direction of the Board of Directors. The Board of Directors
shall have authority to fix the compensation of directors for services in any
lawful capacity.

Each director shall exercise such powers and otherwise perform such
duties in good faith, in the manner such director believes to be in the best
interests of the corporation, and with care, including reasonable inquiry,
using ordinary prudence, as a person in a like position would use under similar
circumstances. (Section 309).

Section 2. EXCEPTION FOR CLOSE CORPORATION. Notwithstanding the
provisions of Section 1, in the event that this corporation shall elect to
become a close corporation as defined in Section 186, its shareholders may
enter into a Shareholders' Agreement as provided in Section 300 (b). Said
Agreement may provide for the exercise of corporate powers and the management
of the business and affairs of this corporation by the shareholders, provided
however such agreement shall, to the extent and so long as the discretion or
the powers of the Board in its management of corporate affairs is controlled by
such agreement, impose upon each shareholder who is a party thereof, liability
for managerial acts performed or omitted by such person pursuant thereto
otherwise imposed upon Directors as provided in Section 300 (d).

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Section 3. QUALIFICATIONS AND NUMBER. A director need not be a
shareholder of the corporation, a citizen, of the United States, or a resident
of the State of California. The authorized number of directors constituting the
Board of Directors until further changed shall be ______________. Thereafter,
the authorized number of directors constituting the Board shall be at least
three provided that, whenever corporation shall have only two shareholders, the
number directors may be at least two, and, whenever the corporation shall have
only one shareholder, the number of directors may be at least one. Subject to
the foregoing provisions, the number of directors may be changed from time to
time by an amendment of these Bylaws adopted by the shareholders. Any such
amendment reducing the number of directors to fewer than five cannot be adopted
if the votes cast against its adoption at a meeting or the shares not
consenting in writing in the case of action by written consent are equal to
more than sixteen and two-thirds percent of the outstanding shares. No
decrease in the authorized number of directors shall have the effect of
shortening the term of any incumbent director.

Section 4. ELECTION AND TERM. The initial Board of Directors shall
consist of the persons elected at the meeting of the incorporator, all of whom
shall hold office until the first annual meeting of shareholders and until
their successors have been elected and qualified, or until their earlier
resignation or removal from office. Thereafter, directors who are elected to
replace any or all of the members of the initial Board of Directors or who are
elected at an annual meeting of shareholders, and directors who are elected in
the interim to fill vacancies, shall hold office until the next annual meeting
of shareholders and until their successors have been elected and qualified, or
until their earlier resignation, removal from office, or death. In the interim
between annual meetings of shareholders or of special meetings of shareholders
called for the election of directors, any vacancies in the Board of Directors,
including vacancies resulting from an increase in the authorized number of
directors which have not been filled by the shareholders, including any other
vacancies which the General Corporation Law authorizes directors to fill, and
including vacancies resulting from the removal of directors which are not
filled at the meeting of shareholders at which any such removal has been
effected, if the Articles of Incorporation or a By-Law adopted by the
shareholders so provides, may be filled by the vote of a majority of the
directors then in office or of the sole remaining director, although less than
a quorum exists. Any director may resign effective upon giving written notice
to the Chairman of the Board, if any, the President, the Secretary or the Board
of Directors, unless the notice specifies a later time for the effectiveness of
such resignation. If the resignation is effective at a future time, a
successor may be elected to the office when the resignation becomes effective.

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The shareholders may elect a director at any time to fill any vacancy
which the directors are entitled to fill, but which they, have not filled. Any
such election by written consent shall require the consent of a majority of the
shares.

Section 5. INDEMNIFICATION OF DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS.
The corporation may indemnify any Director, Officer, agent or employee as to
those liabilities and on those terms and conditions as are specified in Section
317 In any event, the corporation shall have the right to purchase and maintain
insurance on behalf of any such persons whether or not the corporation would
have the power to indemnify such person against the liability insured against.

Section 6. MEETINGS.

TIME. Meetings shall be held at such time as the Board shall fix,
except that the first meeting of a newly elected Board shall be held as soon
after its election as the directors may conveniently assemble.

PLACE. Meetings may be held at any place, within or without the State
of California, which has been designated in any notice of the meeting, or, if
not stated in said notice, or, if there is no notice given, at the place
designated by resolution of the Board of Directors.

CALL. Meetings may be called by the Chairman of the Board, if any
and acting, by the Vice Chairman of the Board, if any, by the President, if
any, by any vice President or Secretary, or by any two directors.

NOTICE AND WAIVER THEREOF. No notice shall be required for regular
meetings for which the time and place have been fixed by the Board of
Directors. Special meetings shall be held upon at least four days' notice by
mail or upon at least forty-eight hours' notice delivered personally or by
telephone or telegraph. Notice of a meeting need not be given to any director
who signs a waiver of notice, whether before or after the meeting, or who
attends the meeting without protesting, prior thereto or at its commencement,
the lack of notice to such director. A notice or waiver of notice need not
specify the purpose of any regular or special meeting of the Board of
Directors.

Section 7. SOLE DIRECTOR PROVIDED BY ARTICLES OF INCORPORATION. In the
event only one director is required by the Bylaws or Articles of Incorporation,
then any reference herein to notices, waivers, consents, meetings or other
actions by a majority or quorum of the directors shall be deemed to refer to
such notice, waiver, etc., by such sole director, who shall have all the rights
and duties and shall be entitled to exercise all of the powers and shall assume
all the responsibilities otherwise herein described as given to a Board of
Directors.

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Section 8. QUORUM AND ACTION. A majority of the authorized number of
directors shall constitute a quorum except when a vacancy or vacancies prevents
such majority, whereupon a majority of the directors in office shall constitute
a quorum, provided such majority shall constitute at least either one-third of
the authorized number of directors or at least two directors, whichever is
larger, or unless the authorized number of directors is only one. A majority
of the directors present, whether or not a quorum is present, may adjourn any
meeting to another time and place. If the meeting is adjourned for more than
twenty-four hours, notice of any adjournment to another time or place shall be
given prior to the time of the adjourned meeting to the directors, if any, who
were not present at the time of the adjournment. Except as the Articles of
Incorporation, these Bylaws and the General Corporation Law may otherwise
provide, the act or decision done or made by a majority of the Directors
present at a meeting duly held at which a quorum is present shall be the act of
the Board of Directors. Members of the Board of Directors may participate in a
meeting through use of conference telephone or similar communications
equipment, so long as all members participating in such meeting can hear one
another, and participation by such use shall be deemed to constitute presence
in person at any such meeting.

A meeting at which a quorum is initially present may continue to
transact business notwithstanding the withdrawal of directors, provided that
any action which may be taken is approved by at least a majority of the
required quorum for such meeting.

Section 9. CHAIRMAN OF THE MEETING. The Chairman of the Board, if any
and if present and acting, the Vice Chairman of the Board, if any and if
present and acting, shall preside at all meetings. Otherwise, the President,
if any and present and acting, or any director chosen by the Board, shall
preside.

Section 10. REMOVAL OF DIRECTORS. The entire Board of Directors or any
individual director may be removed from office without cause by approval of the
holders of at least a majority of the shares provided, that unless the entire
Board is removed, an individual director shall not be removed when the votes
cast against such removal, or not consenting in writing to such removal, would
be sufficient to elect such director if voted cumulatively at an election of
directors at which the same total number of votes were cast, or, if such action
is taken by written consent, in lieu of a meeting, all shares entitled to vote
were voted, and the entire number of directors authorized at the time of the
director's most recent election were then being elected. If any or all
directors are so removed, new directors may be elected at the same meeting or
by such written consent. The Board of Directors may declare vacant the
office of any director who has been declared of unsound mind by an order of
court or convicted of a felony.

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Section 11. COMMITTEES. The Board of Directors, by resolution adopted by
a majority of the authorized number of directors, may designate one or more
committees, each consisting of two or more directors to serve at the pleasure
of the Board of Directors. The Board of Directors may designate one or more
directors as alternate members of any such committee, who may replace any
absent member at any meeting of such committee. Any such committee, to the
extent provided in the resolution of the Board of Directors, shall have all the
authority of the Board of Directors except such authority as may not be
delegated by the provisions of the General Corporation Law.

Section 12. INFORMAL ACTION. The transactions of any meeting of the Board
of Directors, however called and noticed or wherever held, shall be as valid as
though had at a meeting duly held after regular call and notice, if a quorum is
present and if, either before or after the meeting each of the directors not
present signs a written waiver of notice, a consent to holding the meeting, or
an approval of the minutes thereof. All such waivers, consents, or approvals
shall be filed with the corporate records or made a part of the minutes of the
meeting.

Section 13. WRITTEN ACTION. Any action required or permitted to be taken
may be taken without a meeting if all of the members of the Board of Directors
shall individually or collectively consent in writing to such action. Any such
written consent or consents shall be filed with the minutes of the proceedings
of the Board. Such action by written consent shall have the same force and
effect as a unanimous vote of such directors.

ARTICLE III
OFFICERS

Section 1. OFFICERS. The officers of the corporation shall be a Chairman
of the Board or a President or both, a Secretary and a Chief Financial Officer.
The corporation may also have, at the discretion of the Board of Directors, one
or more Vice Presidents, one or more Assistant Secretaries and such other
officers as may be appointed in accordance with the provisions of Section 3 of
this Article. One person may hold two or more offices.

Section 2. ELECTION. The officers of the corporation, except such
officers as may be appointed in accordance with the provisions of Section 3 or
Section 5 of this Article shall be chosen annually by the Board of Directors,
and each shall hold his office until he shall resign or shall be removed or
otherwise disqualified to serve, or his successor shall be elected and
qualified.

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Section 3. SUBORDINATE OFFICERS, ETC. The Board of Directors may appoint
such other officers as the business of the corporation may require, each of
whom shall hold office for such period, have such authority and perform such
duties as are provided in the Bylaws or as the Board of Directors may from time
to time determine.

Section 4. REMOVAL AND RESIGNATION. Any officer may be removed, either
with or without cause, by a majority of the directors at the time in office,
at any regular or special meeting of the Board, or, except in case of an
officer chosen by the Board of Directors, by any officer upon whom such power
of removal may be conferred by the Board of Directors.

Any officer may resign at any time by giving written notice to the
Board of Directors, or to the President, or to the Secretary of the
corporation. Any such resignation shall take effect at the date of the receipt
of such notice or at any later time specified therein; and, unless otherwise
specified therein, the acceptance of such resignation shall not be necessary to
make it effective.

Section 5. VACANCIES. A vacancy in any office because of death,
resignation, removal, disqualification or any other cause shall be filled in
the manner prescribed in the Bylaws for regular appointments to such office.

Section 6. CHAIRMAN OF THE BOARD. The Chairman of the Board, if there
shall be such an officer, shall, if present, preside at all meetings of the
Board of Directors, and exercise and perform such other powers and duties as
may be from time to time assigned to him by the Board of Directors or
prescribed by the Bylaws.

Section 7. PRESIDENT. Subject to such supervisory powers, if any, as
may be given by the Board of Directors to the Chairman of the Board, if there
be such an officer, the President shall be the Chief Executive Officer of the
corporation and shall, subject to the control of the Board of Directors, have
general supervision, direction and control of the business and officers of the
corporation. He shall preside at all meetings of the shareholders and in the
absence of the Chairman of the Board, or if there be none, at all meetings of
the Board of Directors. He shall be ex officio a member of all the standing
committees, including the Executive Committee, if any, and shall have the
general powers and duties of management usually vested in the office of
President of a corporation, and shall have such other powers and duties as may
be prescribed by the Board of Directors or the Bylaws.

Section 8. VICE PRESIDENT. In the absence or disability of the
President, the Vice Presidents, in order of their rank as fixed by the Board of
Directors, or if not ranked, the Vice President designated by the Board of
Directors, shall perform all the duties of the President, and when so acting
shall have

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all the powers of, and be subject to, all the restrictions upon, the
President. The Vice Presidents shall have such other powers and perform such
other duties as from time to time may be prescribed for them respectively by
the Board of Directors or the Bylaws.

Section 9. SECRETARY. The Secretary shall keep, or cause to be kept, a
book of minutes at the principal office or such other place as the Board of
Directors may order, of all meetings of Directors and Shareholders, with the
time and place of holding, whether regular or special, and if special, how
authorized, the notice thereof given, the names of those present at Directors'
meetings, the number of shares present or represented at Shareholders' meetings
and the proceedings thereof.

The Secretary shall keep, or cause to be kept, at the principal office
or at the office of the corporation's transfer agent, a share register, or
duplicate share register, showing the names of the shareholders and their
addresses; the number and classes of shares held by each; the number and date
of certificates issued for the same; and the number and date of cancellation of
every certificate surrendered for cancellation.

The Secretary shall give, or cause to be given, notice of all the
meetings of the shareholders and of the Board of Directors required by the
Bylaws or by law to be given, and he shall keep the seal of the corporation
in safe custody, and shall have such other powers and perform such other duties
as may be prescribed by the Board of Directors or by the Bylaws.

Section 10. CHIEF FINANCIAL OFFICER. This officer shall keep and
maintain, or cause to be kept and maintained in accordance with generally
accepted accounting principles, adequate and correct accounts of the properties
and business transactions of the corporation, including accounts of its assets,
liabilities, receipts, disbursements, gains, losses, capital, earnings (or
surplus) and shares. The books of account shall at all reasonable times be
open to inspection by any director.

This officer shall deposit all monies and other valuables in the name
and to the credit of the corporation with such depositories as may be
designated by the Board of Directors. He shall disburse the funds of the
corporation as may be ordered by the Board of Directors, shall render to the
President and directors, whenever they request it, an account of all his
transactions and of the financial condition of the corporation, and shall have
such other powers and perform such other duties as may be prescribed by the
Board of Directors or the Bylaws.

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ARTICLE IV
CERTIFICATES AND TRANSFERS OF SHARES

Section 1. CERTIFICATES FOR SHARES. Each certificate for shares of the
corporation shall set forth therein the name of the record holder of the shares
represented thereby, the number of shares and the class or series of shares
owned by said holder, the par value, if any, of the shares represented thereby,
and such other statements, as applicable, prescribed by Sections 416 - 419,
inclusive, and other relevant Sections of the General Corporation Law of the
State of California (the "General Corporation Law") and such other statements,
as applicable, which may be prescribed by the Corporate Securities Law of the
State of California and any other applicable provision of the law. Each such
certificate issued shall be signed in the name of the corporation by the
Chairman of the Board of Directors, if any, or the Vice Chairman of the Board
of Directors, if any, the President, if any, or a Vice President, if any, and
by the Chief Financial Officer or an Assistant Treasurer or the Secretary or an
Assistant Secretary. Any or all of the signatures on a certificate for shares
may be a facsimile. In case any officer, transfer agent or registrar who has
signed or whose facsimile signature has been placed upon a certificate for
shares shall have ceased to be such officer, transfer agent or registrar before
such certificate is issued, it may be issued by the corporation with the same
effect as if such person were an officer, transfer agent or registrar at the
date of issue.

In the event that the corporation shall issue the whole or any part of
its shares as partly paid and subject to call for the remainder of the
consideration to be paid therefor, any such certificate for shares shall set
forth thereon the statements prescribed by Section 409 of the General
Corporation Law.

Section 2. LOST OR DESTROYED CERTIFICATES FOR SHARES. The corporation
may issue a new certificate for shares or for any other security in the place
of any other certificate theretofore issued by it, which is alleged to have
been lost, stolen or destroyed. As a condition to such issuance, the
corporation may require any such owner of the allegedly lost, stolen or
destroyed certificate or any such owner's legal representative to give the
corporation a bond, or other adequate security, sufficient to indemnify it
against any claim that may be made against it, including any expense or
liability, on account of the alleged loss, theft or destruction of any such
certificate or the issuance of such new certificate.

Section 3. SHARE TRANSFERS. Upon compliance with any provisions of the
General Corporation Law and/or the Corporate Securities Law of 1968 which may
restrict the transferability of shares, transfers of shares of the corporation
shall be made only on the record of shareholders of the corporation by

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the registered holder thereof, or by his attorney thereunto authorized by power
of attorney duly executed and filed with the Secretary of the corporation or
with a transfer agent or a registrar, if any, and on surrender of the
certificate or certificates for such shares properly endorsed and the payment
of all taxes, if any, due thereon.

Section 4. RECORD DATE FOR SHAREHOLDERS. In order that the corporation
may determine the shareholders entitled to notice of any meeting or to vote or
be entitled to receive payment of any dividend or other distribution or
allotment of any rights or entitled to exercise any rights in respect of any
other lawful action, the Board of Directors may fix, in advance a record date,
which shall not be more than sixty days or fewer than ten days prior to the
date of such meeting or more than sixty days prior to any other action.

If the Board of Directors shall not have fixed a record date as
aforesaid, the record date for determining shareholders entitled to notice of
or to vote at a meeting of shareholders shall be at the close of business on
the business day next preceding the day on which notice is given or, if notice
is waived, at the close of business on the business day next preceding the day
on which the meeting is held; the record date for determining shareholders
entitled to give consent to corporate action in writing without a meeting, when
no prior action by the Board of Directors has been taken, shall be the day on
which the first written consent is given; and the record date for determining
shareholders for any other purpose shall be at the close of business on the day
on which the Board of Directors adopts the resolution relating thereto, or the
sixtieth day prior to the day of such other action, whichever is later.

A determination of shareholders of record entitled to notice of or to
vote at a meeting of shareholders shall apply to any adjournment of the meeting
unless the Board of Directors fixes a new record date for the adjourned
meeting, but the Board of Directors shall fix a new record date if the meeting
is adjourned for more than forty-five days from the date set for the original
meeting.

Except as may be otherwise provided by the General Corporation Law,
shareholders on the record date shall be entitled to notice and to vote or to
receive any dividend, distribution or allotment of rights or to exercise the
rights, as the case may be, notwithstanding any transfer of any shares on the
books of the corporation after the record date.

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Section 5. REPRESENTATION OF SHARES IN OTHER CORPORATIONS. Shares of
other corporations standing in the name of this corporation may be voted or
represented and all incidents thereto may be exercised on behalf of the
corporation by the Chairman of the Board, the President or any Vice President
or any other person authorized by resolution of the Board of Directors.

Section 6. MEANING OF CERTAIN TERMS. As used in these Bylaws in respect
of the right to notice of a meeting of shareholders or a waiver thereof or to
participate or vote thereat or to assent or consent or dissent in writing in
lieu of a meeting, as the case may be, the term "share" or "shares" or
"shareholder" or "shareholders" refers to an outstanding share or shares and to
a holder or holders record or outstanding shares when the corporation is
authorized to issue only one class of shares, and said reference is also
intended to include any outstanding share or shares and any holder or holders
of record of outstanding shares of any class upon which or upon whom the
Articles of Incorporation confer such rights here there are two or more classes
or series of shares or upon which or upon whom the General Corporation Law
confers such rights notwithstanding that the Articles of Incorporation may
provide for more than one class or series of shares, one or more of which are
limited or denied such rights thereunder.

Section 7. CLOSE CORPORATION CERTIFICATES. All certificates representing
shares of this corporation, in the event it shall elect to become a close
corporation, shall contain the legend required by Section 418(c).

ARTICLE V
EFFECT OF SHAREHOLDERS' AGREEMENT-CLOSE CORPORATION

Any Shareholders' Agreement authorized by Section 300(b) shall only be
effective to modify the terms of these Bylaws if this corporation elects to
become a close corporation with appropriate filing of or amendment to its
Articles as required by Section 202 and shall terminate when this corporation
ceases to be a close corporation. Such an agreement cannot waive or alter
Sections 158 (defining close corporations), 202 (requirements of Articles of
Incorporation), 500 and 501 relative to distributions, 111 (merger), 1201(e)
(reorganization) or Chapters 15 (Records and Reports, 16 (Rights of Inspection),
18 (Involuntary Dissolution) or 2 (Crimes and Penalties). Any other provisions
of the Code or these Bylaws may be altered or waived thereby, but to the extent
they are not so altered or waived, these Bylaws shall be applicable.

BYLAWS
- 14 -
<PAGE> 15

ARTICLE VI
CORPORATE CONTRACTS AND INSTRUMENTS - HOW EXECUTED

The Board of Directors, except as in the Bylaws otherwise provided, may
authorize any officer or officers, agent or agents, to enter into any contract
or execute any instrument in the name of and on behalf of the corporation. Such
authority may be general or confined to specific instances. Unless so
authorized by the Board of Directors, no officer, agent or employee shall have
any power or authority to bind the corporation by any contract or agreement, or
to pledge its credit, or to render it liable for any purposes or any amount,
except as provided in Section 313 of the Corporations Code.

ARTICLE VII
CONTROL OVER BYLAWS

After the initial Bylaws of the corporation shall have been adopted by
the incorporator or incorporators of the corporation, the Bylaws may be amended
or repealed or new Bylaws may be adopted by the shareholders entitled to
exercise a majority of the voting power or by the Board of Directors; provided,
however, that the Board of Directors shall have no control over any By-Law
which fixes or changes the authorized number of directors of the corporation;
provided, further, than any control over the Bylaws herein vested in the Board
of Directors shall be subject to the authority of the aforesaid shareholders to
amend or repeal the Bylaws or to adopt new Bylaws; and provided further that
any By-Law amendment or new By-Law which changes the minimum number of
directors to fewer than five shall require authorization by the greater
proportion of voting power of the shareholders as hereinbefore set forth.

ARTICLE VIII
BOOKS AND RECORDS

Section 1. RECORDS: STORAGE AND INSPECTION. The corporation shall keep
at its principal executive office in the State of California, or, if its
principal executive office is not in the State of California, the original or a
copy of the Bylaws as amended to date, which shall be open to inspection by the
shareholders at all reasonable times during office hours. If the principal
executive office of the corporation is outside the State of California, and, if
the corporation has no principal business office in the State of California, it
shall upon request of any shareholder furnish a copy of the Bylaws as amended
to date.

The corporation shall keep adequate and correct books and records of
account and shall keep minutes of the proceedings of its shareholders, Board
of Directors and committees, if any, of the Board of Directors. The corporation
shall keep at its principal executive office, or at the office of its transfer
agent or registrar, a record of its shareholders,

BYLAWS
- 15 -
<PAGE> 16
giving the names and addresses of all shareholders and the number and class of
shares held by each. Such minutes shall be in written form. Such other books
and records shall be kept either in written form or in any other form capable
of being converted into written form.

Section 2. RECORD OF PAYMENTS. All checks, drafts or other orders or
payment of money, notes or other evidences of indebtedness, issued in the name
of or payable to the corporation, shall be signed or endorsed by such person or
persons and in such manner as shall be determined from time to time by
resolution of the Board of Directors.

Section 3. ANNUAL REPORT. Whenever the corporation shall have fewer than
one hundred shareholders, the Board of Directors shall not be required to cause
to be sent to the shareholders of the corporation the annual report prescribed
by Section 1501 of the General Corporation Law unless it shall determine that a
useful purpose would be served by causing the same to be sent or unless the
Department of Corporations, pursuant to the provisions of the Corporate
Securities Law of 1968, shall direct the sending of the same.

BYLAWS
- 16 -
<PAGE> 17

CERTIFICATE OF ADOPTION OF BYLAWS

ADOPTION BY FIRST DIRECTOR(S).

The undersigned person(s) appointed in the Articles of Incorporation
to act as the Incorporator(s) or First Director(s) of the above-named
corporation hereby adopt the same as the Bylaws of said corporation.

Executed this 15th day of August, 1994.

-----------------------------------
MARSHALL FIELD Name

THIS IS TO CERTIFY:

That I am the duly-elected, qualified and acting Secretary of
the above-named corporation; that the foregoing Bylaws were adopted as the
Bylaws of said corporation on the date set forth above by the person(s)
appointed in the Articles of Incorporation to act as the Incorporator(s) or
First Director(s) of said corporation.

IN WITNESS WHEREOF, I have hereunto set my hand and affixed
the corporate seal this 15th day of August 1994.

-----------------------------------
MARSHALL FIELD, Secretary

(SEAL)

CERTIFICATE BY SECRETARY OF ADOPTION BY SHAREHOLDERS' VOTE. THIS IS TO CERTIFY:

That I am the duly elected, qualified and acting Secretary of
the above-named corporation and that the above and foregoing Code of Bylaws was
submitted to the shareholders at their first meeting held on the date set forth
in the Bylaws and recorded in the minutes thereof, was ratified by the vote of
shareholders entitled to exercise the majority of the voting power of said
corporation.

IN WITNESS WHEREOF, I have hereunto set my hand this
15th day of August, 1994.

-----------------------------------
MARSHALL FIELD, Secretary

BYLAWS
- 17 -

<PAGE> 1
A.A.P.L. FORM 610-1982

MODEL FORM OPERATING AGREEMENT

[AMERICAN ASSOCIATION OF PETROLEUM LANDMEN LOGO]

OPERATING AGREEMENT

DATED

MAY 1, 1996

OPERATOR BLACKJACK OIL & GAS, INC.
------------------------------------------------------------------------

CONTRACT AREA OKLAHOMA, TEXAS, KANSAS
-------------------------------------------------------------------

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

COUNTY OR PARISH OF STATE OF
-------------------------------------- ---------------

COPYRIGHT 1982 - ALL RIGHTS RESERVED
AMERICAN ASSOCIATION OF PETROLEUM
LANDMEN, 4100 FOSSIL CREEK BLVD.
FORT WORTH, TEXAS 76137, APPROVED FORM.
A.A.P.L. NO. 610 - 1982 REVISED
<PAGE> 2
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

GUIDANCE IN THE PREPARATION OF THIS AGREEMENT:

1. Title Page - Fill in blanks as applicable.

2. Preamble, Page I - Enter name of Operator.

3. Article II - Exhibits:
(a) Indicate Exhibits to be attached.
(b) If it is desired that no reference be made to non-discrimination,
the reference to Exhibit "F" should be deleted.

4. Article III.B. - Interests of Parties in Costs and Production - Enter
royalty fraction as agreed to by parties.

5. Article IV.A. - Title Examination - Select option as agreed to by the
parties.

6. Article IV.B. - Loss of Title - If "Joint Loss" of Title is desired, the
following changes should be made:
(a) Delete Articles IV.B.1 and IV.B.2.
(b) Article IV.B.3 - Delete phrase "other than those set forth in
Articles IV.B.1 and IV.B.2 above."
(c) Article VII.E. - Change reference at end of the first grammatical
paragraph from "Article IV.B.2" to "Article IV,B.3."
(d) Article X. - Add as the concluding sentence - "All claims or
suits involving title to any interest subject to this agreement
shall be treated as a claim or a suit against all parties
hereto."

7. Article V - Operator - Enter name of Operator.

8. Article VI.A. - Initial Well:
(a) Date of commencement of drilling.
(b) Location of well.
(c) Obligation depth.

9. Article VI.B.2.(b) - Subsequent Operations - Enter penalty percentage as
agreed to by parties.

10. Article VI.C. - Taking Production in Kind - If a Gas Balancing Agreement
is not in existence nor attached hereto as Exhibit "E", then use
Alternate Page 8.

11. Article VII.D.1. - Limitation of Expenditures - Select option as agreed
to by parties.

12. Article VII.D.3. - Limitation of Expenditures - Enter limitation of
expenditure of Operator for single project and amount above which
Operator may furnish information AFE.

13. Article IX. - Internal Revenue Code Election - Delete this article in
the event the agreement is a Tax Partnership and Exhibit "G" is
attached.

14. Article X. - Claims and Lawsuits - Enter claim limit as agreed to by
parties.

15. Article XIII. - Term of Agreement:
(a) Select Option as agreed to by parties.
(b) If Option No. 2 is selected, enter agreed number of days in two
(2) blanks.

16. Article XIV.B - Governing Law - Enter state as agreed to by parties.

17. Signature Page - Enter effective date.

[AMERICAN ASSOCIATION OF PETROLEUM LANDMEN LOGO]

I
<PAGE> 3
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Article Title Page
- ------- ----- ----
<S> <C> <C>
I. DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

II. EXHIBITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

III. INTERESTS OF PARTIES . . . . . . . . . . . . . . . . . . . . . . . . 2
A. OIL AND GAS INTERESTS . . . . . . . . . . . . . . . . . . . . . . 2
B. INTERESTS OF PARTIES IN COSTS AND PRODUCTION . . . . . . . . . . 2
C. EXCESS ROYALTIES, OVERRIDING ROYALTIES AND OTHER PAYMENTS . . . . 2
D. SUBSEQUENTLY CREATED INTERESTS . . . . . . . . . . . . . . . . . 2

IV. TITLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
A. TITLE EXAMINATION . . . . . . . . . . . . . . . . . . . . . . . . 2-3
B. LOSS OF TITLE . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1. Failure of Title . . . . . . . . . . . . . . . . . . . . . . 3
2. Loss by Non-Payment or Erroneous Payment of Amount Due . . . . 3
3. Other Losses . . . . . . . . . . . . . . . . . . . . . . . . 3

V. OPERATOR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
A. DESIGNATION AND RESPONSIBILITIES OF OPERATOR . . . . . . . . . . 4
B. RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR . . 4
1. Resignation or Removal of Operator . . . . . . . . . . . . . 4
2. Selection of Successor Operator . . . . . . . . . . . . . . . 4
C. EMPLOYEES . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
D. DRILLING CONTRACTS . . . . . . . . . . . . . . . . . . . . . . . 4

VI. DRILLING AND DEVELOPMENT . . . . . . . . . . . . . . . . . . . . . . 4
A. INITIAL WELL . . . . . . . . . . . . . . . . . . . . . . . . . . 4-5
B. SUBSEQUENT OPERATIONS . . . . . . . . . . . . . . . . . . . . . . 5
1. Proposed Operations . . . . . . . . . . . . . . . . . . . . . 5
2. Operations by Less than All Parties . . . . . . . . . . . . . 5-6-7
3. Stand-By Time . . . . . . . . . . . . . . . . . . . . . . . . 7
4. Sidetracking . . . . . . . . . . . . . . . . . . . . . . . . 7
C. TAKING PRODUCTION IN KIND . . . . . . . . . . . . . . . . . . . . 7
D. ACCESS TO CONTRACT AREA AND INFORMATION . . . . . . . . . . . . . 8
E. ABANDONMENT OF WELLS . . . . . . . . . . . . . . . . . . . . . . 8
1. Abandonment of Dry Holes . . . . . . . . . . . . . . . . . . 8
2. Abandonment of Wells that have Produced . . . . . . . . . . . 8-9
3. Abandonment of Non-Consent Operations . . . . . . . . . . . . 9

VII. EXPENDITURES AND LIABILITY OF PARTIES . . . . . . . . . . . . . . . . 9
A. LIABILITY OF PARTIES . . . . . . . . . . . . . . . . . . . . . . 9
B. LIENS AND PAYMENT DEFAULTS . . . . . . . . . . . . . . . . . . . 9
C. PAYMENTS AND ACCOUNTING . . . . . . . . . . . . . . . . . . . . . 9
D. LIMITATION OF EXPENDITURES . . . . . . . . . . . . . . . . . . . 9-10
1. Drill or Deepen . . . . . . . . . . . . . . . . . . . . . . . 9-10
2. Rework or Plug Back . . . . . . . . . . . . . . . . . . . . . 10
3. Other Operations . . . . . . . . . . . . . . . . . . . . . . 10
E. RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES . . . . . . 10
F. TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
G. INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

VIII. ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST . . . . . . . . . . 11
A. SURRENDER OF LEASES . . . . . . . . . . . . . . . . . . . . . . . 11
B. RENEWAL OR EXTENSION OF LEASES . . . . . . . . . . . . . . . . . 11
C. ACREAGE OR CASH CONTRIBUTIONS . . . . . . . . . . . . . . . . . . 11-12
D. MAINTENANCE OF UNIFORM INTEREST . . . . . . . . . . . . . . . . . 12
E. WAIVER OF RIGHTS TO PARTITION . . . . . . . . . . . . . . . . . . 12
F. PREFERENTIAL RIGHT TO PURCHASE . . . . . . . . . . . . . . . . . 12

IX. INTERNAL REVENUE CODE ELECTION . . . . . . . . . . . . . . . . . . . 12

X. CLAIMS AND LAWSUITS . . . . . . . . . . . . . . . . . . . . . . . . . 13

XI. FORCE MAJEURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

XII. NOTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

XIII. TERM OF AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . 13

XIV. COMPLIANCE WITH LAWS AND REGULATIONS . . . . . . . . . . . . . . . . 14
A. LAWS, REGULATIONS AND ORDERS . . . . . . . . . . . . . . . . . . 14
B. GOVERNING LAW . . . . . . . . . . . . . . . . . . . . . . . . . . 14
C. REGULATORY AGENCIES . . . . . . . . . . . . . . . . . . . . . . . 14

XV. OTHER PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . . . . 14

XVI. MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
</TABLE>

[AMERICAN ASSOCIATION OF PETROLEUM LANDMEN LOGO]

II
<PAGE> 4
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

OPERATING AGREEMENT

THIS AGREEMENT entered into by and between Blackjack Oil & Gas, Inc.
P.O. Box 5127 Enid, OK 73702, hereinafter designated and referred to as
"Operator", and the signatory party or parties other than Operator, sometimes
hereinafter referred to individually herein as "Non-Operator", and collectively
as "Non-Operators".

WITNESSETH:

WHEREAS, the parties to this agreement are owners of oil and gas leases
and/or oil and gas interests in the land identified in Exhibit "A", and the
parties hereto have reached an agreement to explore and develop these leases
and/or oil and gas interests for the production of oil and gas to the extent
and as hereinafter provided,

NOW, THEREFORE, it is agreed as follows:

ARTICLE I.
DEFINITIONS

As used in this agreement, the following words and terms shall have the
meanings here ascribed to them:

A. The term "oil and gas" shall mean oil, gas, casinghead gas, gas
condensate, and all other liquid or gaseous hydrocarbons and other marketable
substances produced therewith, unless an intent to limit the inclusiveness of
this term is specifically stated.

B. The terms "oil and gas lease", "lease" and "leasehold" shall mean the
oil and gas leases covering tracts of land lying within the Contract Area which
are owned by the parties to this agreement.

C. The term "oil and gas interests" shall mean unleased fee and mineral
interests in tracts of land lying within the Contract Area which are owned by
parties to this agreement.

D. The term "Contract Area" shall mean all of the lands, oil and gas
leasehold interests and oil and gas interests intended to be developed and
operated for oil and gas purposes under this agreement. Such lands, oil and gas
leasehold interests and oil and gas interests are described in Exhibit "A".

E. The term "drilling unit" shall mean the area fixed for the drilling
of one well by order or rule of any state or federal body having authority. If
a drilling unit is not fixed by any such rule or order, a drilling unit shall
be the drilling unit as established by the pattern of drilling in the Contract
Area or as fixed by express agreement of the Drilling Parties.

F. The term "drillsite" shall mean the oil and gas lease or interest on
which a proposed well is to be located.

G. The terms "Drilling Party" and "Consenting Party" shall mean a party
who agrees to join in and pay its share of the cost of any operation conducted
under the provisions of this agreement.

H. The terms "Non-Drilling Party" and "Non-Consenting Party" shall mean
a party who elects not to participate in a proposed operation.

Unless the context otherwise clearly indicates, words used in the
singular include the plural, the plural includes the singular, and the neuter
gender includes the masculine and the feminine.

ARTICLE II.
EXHIBITS

The following exhibits, as indicated below and attached hereto, are
incorporated in and made a part hereof:

[ ] A. Exhibit "A", shall include the following information:
(1) Identification of lands subject to this agreement,
(2) Restrictions, if any, as to depths, formations, or substances,
(3) Percentages or fractional interests of parties to this agreement,
(4) Oil and gas leases and/or oil and gas interests subject to this
agreement,
(5) Addresses of parties for notice purposes.
[ ] B. Exhibit "B", Form of Lease.
[X] C. Exhibit "C", Accounting Procedure.
[ ] D. Exhibit "D", Insurance.
[ ] E. Exhibit "E", Gas Balancing Agreement.
[ ] F. Exhibit "F", Non-Discrimination and Certification of Non-Segregated
Facilities.
[ ] G. Exhibit "G", Tax Partnership.

If any provision of any exhibit, except Exhibits "E" and "G", is
inconsistent with any provision contained in the body of this agreement, the
provisions in the body of this agreement shall prevail.

[AMERICAN ASSOCIATION OF PETROLEUM LANDMEN LOGO]

-1-
<PAGE> 5
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE III.
INTERESTS OF PARTIES

A. OIL AND GAS INTERESTS:

If any party owns an oil and gas interest in the Contract Area, that
interest shall be treated for all purposes of this agreement and during the
term hereof as if it were covered by the form of oil and gas lease attached
hereto as Exhibit "B", and the owner thereof shall be deemed to own both the
royalty interest reserved in such lease and the interest of the lessee
thereunder.

B. INTERESTS OF PARTIES IN COSTS AND PRODUCTION:

Unless changed by other provisions, all costs and liabilities incurred
in operations under this agreement shall be borne and paid, and all equipment
and materials acquired in operations on the Contract Area shall be owned, by
the parties as their interests are set forth in Exhibit "A". In the same
manner, the parties shall also own all production of oil and gas from the
Contract Area subject to the payment of royalties which shall be borne as
hereinafter set forth.

Regardless of which party has contributed the lease(s) and/or oil and
gas interest(s) hereto on which royalty is due and payable, each party entitled
to receive a share of production of oil and gas from the Contract Area shall
bear and shall pay or deliver, or cause to be paid or delivered, to the extent
of its interest in such production, all royalties on its share of production and
shall hold the other parties free from any liability therefor. No party shall
ever be responsible, however, on a price basis higher than the price received by
such party, to any other party's lessor or royalty owner, and if any such other
party's lessor or royalty owner should demand and receive settlement on a higher
price basis, the party contributing the affected lease shall bear the additional
royalty burden attributable to such higher price.

Nothing contained in this Article III.B. shall be deemed an assignment
or cross-assignment of interests covered hereby.

C. EXCESS ROYALTIES, OVERRIDING ROYALTIES AND OTHER PAYMENTS:

Unless changed by other provisions, if the interest of any party in any
lease covered hereby is subject to any royalty, overriding royalty, production
payment or other burden on production in excess of the amount stipulated in
Article III.B., such party so burdened shall assume and alone bear all such
excess obligations and shall indemnify and hold the other parties hereto
harmless from any and all claims and demands for payment asserted by owners of
such excess burden.

D. SUBSEQUENTLY CREATED INTERESTS:

If any party should hereafter create an overriding royalty, production
payment or other burden payable out of production attributable to its working
interest hereunder, or if such a burden existed prior to this agreement and is
not set forth in Exhibit "A", or was not disclosed in writing to all other
parties prior to the execution of this agreement by all parties, or is not a
jointly acknowledged and accepted obligation of all parties (any such interest
being hereinafter referred to as "subsequently created interest" irrespective
of the timing of its creation and the party out of whose working interest the
subsequently created interest is derived being hereinafter referred to as
"burdened party"), and:

1. If the burdened party is required under this agreement to assign
or relinquish to any other party, or parties, all or a portion of
its working interest and/or the production attributable thereto,
said other party, or parties, shall receive said assignment
and/or production free and clear of said subsequently created
interest and the burdened party shall indemnify and save said
other party, or parties, harmless from any and all claims and
demands for payment asserted by owners of the subsequently
created interest; and,

2. If the burdened party fails to pay, when due, its share of
expenses chargeable hereunder, all provisions of Article VII.B.
shall be enforceable against the subsequently created interest in
the same manner as they are enforceable against the working
interest of the burdened party.

ARTICLE IV.
TITLES

A. TITLE EXAMINATION:

Title examination shall be made on the drillsite of any proposed well
prior to commencement of drilling operations or, if the Drilling Parties so
request, title examination shall be made on the leases and/or oil and gas
interests included, or planned to be included, in the drilling unit around such
well. The opinion will include the ownership of the working interest,
minerals, royalty, overriding royalty and production payments under the
applicable leases. At the time a well is proposed, each party contributing
leases and/or oil and gas interests to the drillsite, or to be included in such
drilling unit, shall furnish to Operator all abstracts (including federal lease
status reports), title opinions, title papers and curative material in its
possession free of charge. All such information not in the possession of or
made available to Operator by the parties, but necessary for the examination of
the title, shall be obtained by Operator. Operator shall cause title to be
examined by attorneys on its staff or by outside attorneys. Copies of all
title opinions shall be furnished to each party hereto. The cost incurred by
Operator in this title program shall be borne as follows:

[ ] Option No. 1: Costs incurred by Operator in procuring abstracts and
title examination (including preliminary, supplemental, shut-in gas royalty
opinions and division order title opinions) shall be a part of the
administrative overhead as provided in Exhibit "C", and shall not be a direct
charge, whether performed by Operator's staff attorneys or by outside
attorneys.

[AMERICAN ASSOCIATION OF PETROLEUM LANDMEN LOGO]

-2-
<PAGE> 6
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE IV
CONTINUED

[X] Option No. 2: Costs incurred by Operator in procuring abstracts and fees
paid outside attorneys for title examination (including preliminary,
supplemental, shut-in gas royalty opinions and division order title opinions)
shall be borne by the Drilling Parties in the proportion that the interest of
each Drilling Party bears to the total interest of all Drilling Parties as such
interests appear in Exhibit "A". Operator shall make no charge for services
rendered by its staff attorneys or other personnel in the performance of the
above functions.

Each party shall be responsible for securing curative matter and pooling
amendments or agreements required in connection with leases or oil and gas
interests contributed by such party. Operator shall be responsible for the
preparation and recording of pooling designations or declarations as well as
the conduct of hearings before governmental agencies for the securing of
spacing or pooling orders. This shall not prevent any party from appearing on
its own behalf at any such hearing.

No well shall be drilled on the Contract Area until after (1) the title
to the drillsite or drilling unit has been examined as above provided, and (2)
the title has been approved by the examining attorney or title has been
accepted by all of the parties who are to participate in the drilling of the
well.

B. LOSS OF TITLE:

1. Failure of Title: Should any oil and gas interest or lease, or
interest therein, be lost through failure of title, which loss results in a
reduction of interest from that shown on Exhibit "A", the party contributing
the affected lease or interest shall have ninety (90) days from final
determination of title failure to acquire a new lease or other instrument
curing the entirety of the title failure, which acquisition will not be subject
to Article VIII.B., and failing to do so, this agreement, nevertheless, shall
continue in force as to all remaining oil and gas leases and interests: and,

(a) The party whose oil and gas lease or interest is affected by the
title failure shall bear alone the entire loss and it shall not be entitled to
recover from Operator or the other parties any development or operating costs
which it may have theretofore paid or incurred, but there shall be no
additional liability on its part to the other parties hereto by reason of such
title failure;

(b) There shall be no retroactive adjustment of expenses incurred or
revenues received from the operation of the interest which has been lost, but
the interests of the parties shall be revised on an acreage basis, as of the
time it is determined finally that title failure has occurred, so that the
interest of the party whose lease or interest is affected by the title failure
will thereafter be reduced in the Contract Area by the amount of the interest
lost;

(c) If the proportionate interest of the other parties hereto in any
producing well theretofore drilled on the Contract Area is increased by reason
of the title failure, the party whose title has failed shall receive the
proceeds attributable to the increase in such interest (less costs and burdens
attributable thereto) until it has been reimbursed for unrecovered costs paid
by it in connection with such well;

(d) Should any person not a party to this agreement, who is determined
to be the owner of any interest in the title which has failed, pay in any
manner any part of the cost of operation, development, or equipment, such
amount shall be paid to the party or parties who bore the costs which are so
refunded;

(e) Any liability to account to a third party for prior production of
oil and gas which arises by reason of title failure shall be borne by the party
or parties whose title failed in the same proportions in which they shared in
such prior production; and,

(f) No charge shall be made to the joint account for legal expenses,
fees or salaries, in connection with the defense of the interest claimed by any
party hereto, it being the intention of the parties hereto that each shall
defend title to its interest and bear all expenses in connection therewith.

2. Loss by Non-Payment or Erroneous Payment of Amount Due: If, through
mistake or oversight, any rental, shut-in well payment, minimum royalty or
royalty payment, is not paid or is erroneously paid, and as a result a lease or
interest therein terminates, there shall be no monetary liability against the
party who failed to make such payment. Unless the party who failed to make the
required payment secures a new lease covering the same interest within ninety
(90) days from the discovery of the failure to make proper payment, which
acquisition will not be subject to Article VIII.B., the interests of the
parties shall be revised on an acreage basis, effective as of the date of
termination of the lease involved, and the party who failed to make proper
payment will no longer be credited with an interest in the Contract Area on
account of ownership of the lease or interest which has terminated. In the
event the party who failed to make the required payment shall not have been
fully reimbursed, at the time of the loss, from the proceeds of the sale of oil
and gas attributable to the lost interest, calculated on an acreage basis, for
the development and operating costs theretofore paid on account of such
interest, it shall be reimbursed for unrecovered actual costs theretofore paid
by it (but not for its share of the cost of any dry hole previously drilled or
wells previously abandoned) from so much of the following, as is necessary to
effect reimbursement:

(a) Proceeds of oil and gas, less operating expenses, theretofore
accrued to the credit of the lost interest, on in acreage basis, up to the
amount of unrecovered costs;

(b) Proceeds, less operating expenses, thereafter accrued attributable
to the lost interest on an acreage basis, of that portion of oil and gas
thereafter produced and marketed (excluding production from any wells
thereafter drilled) which, in the absence of such lease termination, would be
attributable to the lost interest on an acreage basis, up to the amount of
unrecovered costs, the proceeds of said portion of the oil and gas to be
contributed by the other parties in proportion to their respective interests;
and,

(c) Any monies, up to the amount of unrecovered costs, that may be paid
by any party who is, or becomes, the owner of the interest lost, for the
privilege of participating in the Contract Area or becoming a party to this
agreement.

3. Other Losses: All losses incurred, other than those set forth in
Articles IV.B.1. and IV.B.2. above, shall be joint losses and shall be borne by
all parties in proportion to their interests. There shall be no readjustment of
interests in the remaining portion of the Contract Area.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE V.
OPERATOR

A. DESIGNATION AND RESPONSIBILITIES OF OPERATOR:

BLACKJACK OIL & GAS, INC. P.O. BOX 5127 ENID, OK 73702 shall be the
Operator of the Contract Area, and shall conduct and direct and have full
control of all operations on the Contract Area as permitted and required by,
and within the limits of this agreement. It shall conduct all such operations
in a good and workmanlike manner, but it shall have no liability as Operator to
the other parties for losses sustained or liabilities incurred, except such as
may result from gross negligence or willful misconduct.

B. RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR:

1. Resignation or Removal of Operator: Operator may resign at any time
by giving written notice thereof to Non-Operators. If Operator terminates its
legal existence, no longer owns an interest hereunder in the Contract Area, or
is no longer capable of serving as Operator, Operator shall be deemed to have
resigned without any action by Non-Operators, except the selection of a
successor. Operator may be removed if it fails or refuses to carry out its
duties hereunder, or becomes insolvent, bankrupt or is placed in receivership,
by the affirmative vote of two (2) or more Non-Operators owning a majority
interest based on ownership as shown on Exhibit "A" remaining after excluding
the voting interest of Operator. Such resignation or removal shall not become
effective until 7:00 o'clock A.M. on the first day of the calendar month
following the expiration of ninety (90) days after the giving of notice of
resignation by Operator or action by the Non-Operators to remove Operator,
unless a successor Operator has been selected and assumes the duties of
Operator at an earlier date. Operator, after effective date of resignation or
removal, shall be bound by the terms hereof as a Non-Operator. A change of a
corporate name or structure of Operator or transfer of Operator's interest to
any single subsidiary, parent or successor corporation shall not be the basis
for removal of Operator.

2. Selection of Successor Operator: Upon the resignation or removal of
Operator, a successor Operator shall be selected by the parties. The successor
Operator shall be selected from the parties owning an interest in the Contract
Area at the time such successor Operator is selected. The successor Operator
shall be selected by the affirmative vote of two (2) or more parties owning a
majority interest based on ownership as shown on Exhibit "A"; provided,
however, if an Operator which has been removed fails to vote or votes only to
succeed itself, the successor Operator shall be selected by the affirmative
vote of two (2) or more parties owning a majority interest based on ownership
as shown on Exhibit "A" remaining after excluding the voting interest of the
Operator that was removed.

C. EMPLOYEES:

The number of employees used by Operator in conducting operations
hereunder, their selection, and the hours of labor and the compensation for
services performed shall be determined by Operator, and all such employees
shall be the employees of Operator.

D. DRILLING CONTRACTS:

All wells drilled on the Contract Area shall be drilled on a competitive
contract basis at the usual rates prevailing in the area. If it so desires,
Operator may employ its own tools and equipment in the drilling of wells, but
its charges therefor shall not exceed the prevailing rates in the area and the
rate of such charges shall be agreed upon by the parties in writing before
drilling operations are commenced, and such work shall be performed by Operator
under the same terms and conditions as are customary and usual in the area in
contracts of independent contractors who are doing work of a similar nature.

ARTICLE VI.
DRILLING AND DEVELOPMENT

A. INITIAL WELL: N/A

On or before the ____ day of ____________________, 19_____, Operator
shall commence the drilling of a well for oil and gas at the following
location:

and shall thereafter continue the drilling of the well with due diligence to

unless granite or other practically impenetrable substance or condition in the
hole, which renders further drilling impractical is encountered at a lesser
depth, or unless all parties agree to complete or abandon the well at a
lesser depth.

Operator shall make reasonable tests of all formations encountered
during drilling which give indication of containing oil and gas in quantities
sufficient to test, unless this agreement shall be limited in its application
to a specific formation or formations, in which event Operator shall be
required to test only the formation or formations to which this agreement
may apply.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VI
CONTINUED

If, in Operator's judgment, the well will not produce oil or gas in
paying quantities, and it wishes to plug and abandon the well as a dry hole,
the provisions of Article VI.E.1. shall thereafter apply.

B. SUBSEQUENT OPERATIONS:

1. Proposed Operations: Should any party hereto desire to drill any well
on the Contract Area other than the well provided for in Article VI.A., or to
rework, deepen or plug back a dry hole drilled at the joint expense of all
parties or a well jointly owned by all the parties and not then producing in
paying quantities, the party desiring to drill, rework, deepen or plug back
such a well shall give the other parties written notice of the proposed
operation, specifying the work to be performed, the location, proposed depth,
objective formation and the estimated cost of the operation. The parties
receiving such a notice shall have thirty (30) days after receipt of the notice
within which to notify the party wishing to do the work whether they elect to
participate in the cost of the proposed operation. If a drilling rig is on
location, notice of a proposal to rework, plug back or drill deeper may be
given by telephone and the response period shall be limited to forty-eight (48)
hours, exclusive of Saturday, Sunday and legal holidays. Failure of a party
receiving such notice to reply within the period above fixed shall constitute
an election by that party not to participate in the cost of the proposed
operation. Any notice or response given by telephone shall be promptly
confirmed in writing.

If all parties elect to participate in such a proposed operation,
Operator shall, within ninety (90) days after expiration of the notice period
of thirty (30) days (or as promptly as possible after the expiration of the
forty-eight (48) hour period when a drilling rig is on location, as the case
may be), actually commence the proposed operation and complete it with due
diligence at the risk and expense of all parties hereto; provided, however,
said commencement date may be extended upon written notice of same by Operator
to the other parties, for a period up to thirty (30) additional days if, in the
sole opinion of Operator, such additional time is reasonably necessary to
obtain permits from governmental authorities, surface rights (including
rights-of-way) or appropriate drilling equipment, or to complete title
examination or curative matter required for title approval or acceptance.
Notwithstanding the force majeure provisions of Article XI, if the actual
operation has not been commenced within the time provided (including any
extension thereof as specifically permitted herein) and if any party hereto
still desires to conduct said operation, written notice proposing same must be
resubmitted to the other parties in accordance with the provisions hereof as if
no prior proposal had been made.

2. Operations by Less than All Parties: If any party receiving such
notice as provided in Article VI.B.1. or VII.D.1. (Option No. 2) elects not to
participate in the proposed operation, then, in order to be entitled to the
benefits of this Article, the party or parties giving the notice and such other
parties as shall elect to participate in the operation shall, within ninety
(90) days after the expiration of the notice period of thirty (30) days (or as
promptly as possible after the expiration of the forty-eight (48) hour period
when a drilling rig is on location, as the case may be) actually commence the
proposed operation and complete it with due diligence. Operator shall perform
all work for the account of the Consenting Parties; provided, however, if no
drilling rig or other equipment is on location, and if Operator is a
Non-Consenting Party, the Consenting Parties shall either: (a) request Operator
to perform the work required by such proposed operation for the account of the
Consenting Parties, or (b) designate one (1) of the Consenting Parties as
Operator to perform such work. Consenting Parties, when conducting operations
on the Contract Area pursuant to this Article VI.B.2., shall comply with all
terms and conditions of this agreement.

If less than all parties approve any proposed operation, the proposing
party, immediately after the expiration of the applicable notice period, shall
advise the Consenting Parties of the total interest of the parties approving
such operation and its recommendation as to whether the Consenting Parties
should proceed with the operation as proposed. Each Consenting Party, within
forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after
receipt of such notice, shall advise the proposing party of its desire to (a)
limit participation to such party's interest as shown on Exhibit "A" or (b)
carry its proportionate part of Non-Consenting Parties' interests, and failure
to advise the proposing party shall be deemed an election under (a). In the
event a drilling rig is on location, the time permitted for such a response
shall not exceed a total of forty-eight (48) hours (inclusive of Saturday,
Sunday and legal holidays). The proposing party, at its election, may withdraw
such proposal if there is insufficient participation and shall promptly notify
all parties of such decision.

The entire cost and risk of conducting such operations shall be borne by
the Consenting Parties in the proportions they have elected to bear same under
the terms of the preceding paragraph. Consenting Parties shall keep the
leasehold estates involved in such operations free and clear of all liens and
encumbrances of every kind created by or arising from the operations of the
Consenting Parties. If such an operation results in a dry hole, the Consenting
Parties shall plug and abandon the well and restore the surface location at
their sole cost, risk and expense. If any well drilled, reworked, deepened or
plugged back under the provisions of this Article results in a producer of oil
and/or gas in paying quantities, the Consenting Parties shall complete and
equip the well to produce at their sole cost and risk,

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VI
CONTINUED

and the well shall then be turned over to Operator and shall be operated by it
at the expense and for the account of the Consenting Parties. Upon commencement
of operations for the drilling, reworking, deepening or plugging back of any
such well by Consenting Parties in accordance with the provisions of this
Article, each Non-Consenting Party shall be deemed to have relinquished to
Consenting Parties, and the Consenting Parties shall own and be entitled to
receive, in proportion to their respective interests, all of such
Non-Consenting Party's interest in the well and share of production therefrom
until the proceeds of the sale of such share, calculated at the well, or market
value thereof if such share is not sold, (after deducting production taxes,
excise taxes, royalty, overriding royalty and other interests not excepted by
Article III.D. payable out of or measured by the production from such well
accruing with respect to such interest until it reverts) shall equal the total
of the following:

(a) 100% of each such Non-Consenting Party's share of the cost of any
newly acquired surface equipment beyond the wellhead connections (including,
but not limited to, stock tanks, separators, treaters, pumping equipment and
piping), plus 100% of each such Non-Consenting Party's share of the cost of
operation of the well commencing with first production and continuing until
each such Non-Consenting Party's relinquished interest shall revert to it under
other provisions of this Article, it being agreed that each Non-Consenting
Party's share of such costs and equipment will be that interest which would
have been chargeable to Such Non-Consenting Party had it participated in the
well from the beginning of the operations; and

(b) 300% of that portion of the costs and expenses of drilling,
reworking, deepening, plugging back, testing and completing, after deducting
any cash contributions received under Article VIII.C., and 300% of that portion
of the cost of newly acquired equipment in the well (to and including the
wellhead connections), which would have been chargeable to such Non-Consenting
Party if it had participated therein.

An election not to participate in the drilling or the deepening of a
well shall be deemed an election not to participate in any reworking or
plugging back operation proposed in such a well, or portion thereof, to which
the initial Non-Consent election applied that is conducted at any time prior to
full recovery by the Consenting Parties of the Non-Consenting Party's
recoupment account. Any such reworking or plugging back operation conducted
during the recoupment period shall be deemed part of the cost of operation of
said well and there shall be added to the sums to be recouped by the Consenting
Parties one hundred percent (100%) of that portion of the costs of the
reworking or plugging back operation which would have been chargeable to such
Non-Consenting Party had it participated therein. If such a reworking or
plugging back operation is proposed during such recoupment period, the
provisions of this Article VI.B. shall be applicable as between said
Consenting Parties in said well.

During the period of time Consenting Parties are entitled to receive
Non-Consenting Party's share of production, or the proceeds therefrom,
Consenting Parties shall be responsible for the payment of all production,
severance, excise, gathering and other taxes, and all royalty, overriding
royalty and other burdens applicable to Non-Consenting Party's share of
production not excepted by Article III.D.

In the case of any reworking, plugging back or deeper drilling
operation, the Consenting Parties shall be permitted to use, free of cost, all
casing, tubing and other equipment in the well, but the ownership of all such
equipment shall remain unchanged; and upon abandonment of a well after such
reworking, plugging back or deeper drilling, the Consenting Parties shall
account for all such equipment to the owners thereof, with each party receiving
its proportionate part in kind or in value, less cost of salvage.

Within sixty (60) days after the completion of any operation under this
Article, the party conducting the operations for the Consenting Parties shall
furnish each Non-Consenting Party with an inventory of the equipment in and
connected to the well, and an itemized statement of the cost of drilling,
deepening, plugging back, testing, completing, and equipping the well for
production; or, at its option, the operating party, in lieu of an itemized
statement of such costs of operation, may submit a detailed statement of monthly
billings. Each month thereafter, during the time the Consenting Parties are
being reimbursed as provided above, the party conducting the operations for the
Consenting Parties shall furnish the Non-Consenting Parties with an itemized
statement of all costs and liabilities incurred in the operation of the well,
together with a statement of the quantity of oil and gas produced from it and
the amount of proceeds realized from the sale of the well's working interest
production during the preceding month. In determining the quantity of oil and
gas produced during any month, Consenting Parties shall use industry accepted
methods such as, but not limited to, metering or periodic well tests. Any
amount realized from the sale or other disposition of equipment newly acquired
in connection with any such operation which would have been owned by a Non-
Consenting Party had it participated therein shall be credited against the
total unreturned costs of the work done and of the equipment purchased in
determining when the interest of such Non-Consenting Party shall revert to it
as above provided; and if there is a credit balance, it shall be paid to such
Non-Consenting Party.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VI
CONTINUED

If and when the Consenting Parties recover from a Non-Consenting Party's
relinquished interest the amounts provided for above, the relinquished
interests of such Non-Consenting Party shall automatically revert to it, and,
from and after such reversion, such Non-Consenting Party shall own the same
interest in such well, the material and equipment in or pertaining thereto, and
the production therefrom as such Non-Consenting Party would have been entitled
to had it participated in the drilling, reworking, deepening or plugging back
of said well. Thereafter, such Non-Consenting Party shall be charged with and
shall pay its proportionate part of the further costs of the operation of said
well in accordance with the terms of this agreement and the Accounting
Procedure attached hereto.

Notwithstanding the provisions of this Article VI.B.2., it is agreed
that without the mutual consent of all parties, no wells shall be completed in
or produced from a source of supply from which a well located elsewhere on the
Contract Area is producing, unless such well conforms to the then-existing well
spacing pattern for such source of supply.

The provisions of this Article shall have no application whatsoever to
the drilling of the initial well described in Article VI.A. except (a) as to
Article VII.D.1. (Option No. 2), if selected, or (b) as to the reworking,
deepening and plugging back of such initial well after it has been drilled to
the depth specified in Article VI.A. if it shall thereafter prove to be a dry
hole or, if initially completed for production, ceases to produce in paying
quantities.

3. Stand-By Time: When a well which has been drilled or deepened has
reached its authorized depth and all tests have been completed, and the results
thereof furnished to the parties, stand-by costs incurred pending response to a
party's notice proposing a reworking, deepening, plugging back or completing
operation in such a well shall be charged and borne as part of the drilling or
deepening operation just completed. Stand-by costs subsequent to all parties
responding, or expiration of the response time permitted, whichever first
occurs, and prior to agreement as to the participating interests of all
Consenting Parties pursuant to the terms of the second grammatical paragraph of
Article VI.B.2, shall be charged to and borne as part of the proposed
operation, but if the proposal is subsequently withdrawn because of
insufficient participation, such stand-by costs shall be allocated between the
Consenting Parties in the proportion each Consenting Party's interest as shown
on Exhibit "A" bears to the total interest as shown on Exhibit "A" of all
Consenting Parties.

4. Sidetracking: Except as hereinafter provided, those provisions of
this agreement applicable to a "deepening" operation shall also be applicable
to any proposal to directionally control and intentionally deviate a well from
vertical so as to change the bottom hole location (herein called
"sidetracking"), unless done to straighten the hole or to drill around junk in
the hole or because of other mechanical difficulties. Any party having the
right to participate in a proposed sidetracking operation that does not own an
interest in the affected well bore at the time of the notice shall, upon
electing to participate, tender to the well bore owners its proportionate share
(equal to its interest in the sidetracking operation) of the value of that
portion of the existing well bore to be utilized as follows:

(a) If the proposal is for sidetracking an existing dry hole,
reimbursement shall be on the basis of the actual costs incurred in the
initial drilling of the well down to the depth at which the sidetracking
operation is initiated.

(b) If the proposal is for sidetracking a well which has previously
produced, reimbursement shall be on the basis of the well's salvable materials
and equipment down to the depth at which the sidetracking operation is
initiated, determined in accordance with the provisions of Exhibit "C", less
the estimated cost of salvaging and the estimated cost of plugging and
abandoning.

In the event that notice for a sidetracking operation is given while the
drilling rig to be utilized is on location, the response period shall be
limited to forty-eight (48) hours, exclusive of Saturday, Sunday and legal
holidays; provided, however, any party may request and receive up to eight (8)
additional days after expiration of the forty-eight (48) hours within which to
respond by paying for all stand-by time incurred during such extended response
period. If more than one party elects to take such additional time to respond
to the notice, stand-by costs shall be allocated between the parties taking
additional time to respond on a day-to-day basis in the proportion each
electing party's interest as shown on Exhibit "A" bears to the total interest
as shown on Exhibit "A" of all the electing parties. In all other instances the
response period to a proposal for sidetracking shall be limited to thirty (30)
days.

C. TAKING PRODUCTION IN KIND:

Each party shall take in kind or separately dispose of its proportionate
share of all oil and gas produced from the Contract Area, exclusive of
production which may be used in development and producing operations and in
preparing and treating oil and gas for marketing purposes and production
unavoidably lost. Any extra expenditure incurred in the taking in kind or
separate disposition by any party of its proportionate share of the production
shall be borne by such party. Any party taking its share of production in kind
shall be

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VI
CONTINUED

required to pay for only its proportionate share of such part of Operator's
surface facilities which it uses.

Each party shall execute such division orders and contracts as may be
necessary for the sale of its interest in production from the Contract Area,
and, except as provided in Article VII.B., shall be entitled to receive payment
directly from the purchaser thereof for its share of all production.

In the event any party shall fail to make the arrangements necessary to
take in kind or separately dispose of its proportionate share of the oil and
gas produced from the Contract Area, Operator shall have the right, subject to
the revocation at will by the party owning it, but not the obligation, to
purchase such oil and gas or sell it to others at any time and from time to
time, for the account of the non-taking party at the best price obtainable in
the area for such production. Any such purchase or sale by Operator shall be
subject always to the right of the owner of the production to exercise at any
time its right to take in kind, or separately dispose of, its share of all oil
and gas not previously delivered to a purchaser. Any purchase or sale by
Operator of any other party's share of oil and gas shall be only for such
reasonable periods of time as are consistent with the minimum needs of the
industry under the particular circumstances, but in no event for a period in
excess of one (1) year. Notwithstanding the foregoing, Operator shall not make
a sale, including one into interstate commerce, of any other party's share of
gas production without first giving such other party thirty (30) days notice of
such intended sale.

D. ACCESS TO CONTRACT AREA AND INFORMATION:

Each party shall have access to the Contract at all reasonable times, at
its sole cost and risk to inspect or observe operations, and shall have access
at reasonable times to information pertaining to the development or operation
thereof, including Operator's books and records relating thereto. Operator,
upon request, shall furnish each of the other parties with copies of all forms
or reports filed with governmental agencies, daily drilling reports, well logs,
tank tables, daily gauge and run tickets and reports of stock on hand at the
first of each month, and shall make available samples of any cores or cuttings
taken from any well drilled on the Contract Area. The cost of gathering and
furnishing information to Non-Operator, other than that specified above, shall
be charged to the Non-Operator that requests the information.

E. ABANDONMENT OF WELLS:

1. Abandonment of Dry Holes: Except for any well drilled or deepened
pursuant to Article VI.B.2., any well which has been drilled or deepened under
the terms of this agreement and is proposed to be completed as a dry hole shall
not be plugged and abandoned without the consent of all parties. Should
Operator, after diligent effort, be unable to contact any party, or should any
party fail to reply within forty-eight (48) hours (exclusive of Saturday,
Sunday and legal holidays) after receipt of notice of the proposal to plug and
abandon such well, such party shall be deemed to have consented to the proposed
abandonment. All such wells shall be plugged and abandoned in accordance with
applicable regulations and at the cost, risk and expense of the parties who
participated in the cost of drilling or deepening such well. Any party who
objects to plugging and abandoning such well shall have the right to take over
the well and conduct further operations in search of oil and/or gas subject to
the provisions of Article VI.B.

2. Abandonment of Wells that have Produced: Except for any well in which
a Non-Consent operation has been conducted hereunder for which the Consenting
Parties have not been fully reimbursed as herein provided, any well which has
been completed as a producer shall not be plugged and abandoned without the
consent of all parties. If all parties consent to such abandonment, the well
shall be plugged and abandoned in accordance with applicable regulations and at
the cost, risk and expense of all the parties hereto. If, within thirty (30)
days after receipt of notice of the proposed abandonment of any well, all
parties do not agree to the abandonment of such well, those wishing to continue
its operation from the interval(s) of the formation(s) then open to production
shall tender to each of the other parties its proportionate share of the value
of the well's salvable material and equipment, determined in accordance with
the provisions of Exhibit "C", less the estimated cost of salvaging and the
estimated cost of plugging and abandoning. Each abandoning party shall assign
the non-abandoning parties, without warranty, express or implied, as to title
or as to quantity, or fitness for use of the equipment and material, all of its
interest in the well and related equipment, together with its interest in the
leasehold estate as to, but only as to, the interval or intervals of the
formation or formations then open to production. If the interest of the
abandoning party is or includes an oil and gas interest, such party shall
execute and deliver to the non-abandoning party or parties an oil and gas
lease, limited to the interval or intervals of the formation or formations then
open to production, for a term of one (1) year and so long thereafter as oil
and/or gas is produced from the interval or intervals of the formation or
formations covered thereby, such lease to be on the form attached as Exhibit

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VI
CONTINUED

"B". The assignments or leases so limited shall encompass the "drilling unit"
upon which the well is located. The payments by, and the assignments or leases
to, the assignees shall be in a ratio based upon the relationship of their
respective percentage of participation in the Contract Area to the aggregate of
the percentages of participation in the Contract Area of all assignees. There
shall be no readjustment of interests in the remaining portion of the Contract
Area.

Thereafter, abandoning parties shall have no further responsibility,
liability, or interest in the operation of or production from the well in the
interval or intervals then open other than the royalties retained in any lease
made under the terms of this Article. Upon request, Operator shall continue to
operate the assigned well for the account of the non-abandoning parties at the
rates and charges contemplated by this agreement, plus any additional cost and
charges which may arise as the result of the separate ownership of the assigned
well. Upon proposed abandonment of the producing interval(s) assigned or
leased, the assignor or lessor shall then have the option to repurchase its
prior interest in the well (using the same valuation formula) and participate
in further operations therein subject to the provisions hereof.

3. Abandonment of Non-Consent Operations: The provisions of Article
VI.E.1. or VI.E.2. above shall be applicable as between Consenting Parties in
the event of the proposed abandonment of any well excepted from said Articles;
provided, however, no well shall be permanently plugged and abandoned unless
and until all parties having the right to conduct further operations therein
have been notified of the proposed abandonment and afforded the opportunity to
elect to take over the well in accordance with the provisions of this Article
VI.E.

ARTICLE VII.
EXPENDITURES AND LIABILITY OF PARTIES

A. LIABILITY OF PARTIES:

The liability of the parties shall be several, not joint or collective.
Each party shall be responsible only for its obligations, and shall be liable
only for its proportionate share of the costs of developing and operating the
Contract Area. Accordingly, the liens granted among the parties in Article
VII.B. are given to secure only the debts of each severally. It is not the
intention of the parties to create, nor shall this agreement be construed as
creating, a mining or other partnership or association, or to render the
parties liable as partners.

B. LIENS AND PAYMENT DEFAULTS:

Each Non-Operator grants to Operator a lien upon its oil and gas rights
in the Contract Area, and a security interest in its share of oil and/or gas
when extracted and its interest in all equipment, to secure payment of its
share of expense, together with interest thereon at the rate provided in
Exhibit "C". To the extent that Operator has a security interest under the
Uniform Commercial Code of the state, Operator shall be entitled to exercise
the rights and remedies of a secured party tinder the Code. The bringing of a
suit and the obtaining of judgment by Operator for the secured indebtedness
shall not be deemed an election of remedies or otherwise affect the lien rights
or security interest as security for the payment thereof. In addition, upon
default by any Non-Operator in the payment of its share of expense, Operator
shall have the right, without prejudice to other rights or remedies, to collect
from the purchaser the proceeds from the sale of such Non-Operator's share of
oil and/or gas until the amount owed by such Non-Operator, plus interest, has
been paid. Each purchaser shall be entitled to rely upon Operator's written
statement concerning the amount of any default. Operator grants a like lien and
security interest to the Non-Operators to secure payment of Operator's
proportionate share of expense.

If any party fails or is unable to pay its share of expense within sixty
(60) days after rendition of a statement therefor by Operator, the
non-defaulting parties, including Operator, shall, upon request by Operator,
pay the unpaid amount in the proportion that the interest of each such party
bears to the interest of all such parties. Each party so paying its share of
the unpaid amount shall, to obtain reimbursement thereof, be subrogated to the
security rights described in the foregoing paragraph,

C. PAYMENTS AND ACCOUNTING:

Except as herein otherwise specifically provided, Operator shall
promptly pay and discharge expenses incurred in the development and operation
of the Contract Area pursuant to this Agreement and shall charge each of the
parties hereto with their respective proportionate shares upon the expense
basis provided in Exhibit "C". Operator shall keep an accurate record of the
joint account hereunder, showing expenses incurred and charges and credits made
and received.

Operator, at its election, shall have the right from time to time to
demand and receive from the other parties payment in advance of their
respective shares of the estimated amount of the expense to be incurred in
operations hereunder during the next succeeding month, which right may be
exercised only by submission to each such party of an itemized statement of
such estimated expense, together with an invoice for its share thereof. Each
such statement and invoice for the payment in advance of estimated expense
shall be submitted on or before the 20th day of the next preceding month. Each
party shall pay to Operator its proportionate share of such estimate within
fifteen (15) days after such estimate and invoice is received. If any party
fails to pay its share of said estimate within said time, the amount due shall
bear interest as provided in Exhibit "C" until paid. Proper adjustment shall be
made monthly between advances and actual expense to the end that each party
shall bear and pay its proportionate share of actual expenses incurred, and no
more.

D. LIMITATION OF EXPENDITURES:

1. Drill or Deepen: Without the consent of all parties, no well shall be
drilled or deepened, except any well drilled or deepened pursuant to the
provisions of Article VI.B.2. of this agreement. Consent to the drilling or
deepening shall include:

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VII
CONTINUED

[ ] Option No. 1: All necessary expenditures for the drilling or deepening,
testing, completing and equipping of the well, including necessary tankage
and/or surface facilities.

[ ] Option No. 2: All necessary expenditures for the drilling or deepening
and testing of the well. When such well has reached its authorized depth, and
all tests have been completed, and the results thereof furnished to the
parties, Operator shall give immediate notice to the Non-Operators who have the
right to participate in the completion costs. The parties receiving such notice
shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal
holidays) in which to elect to participate in the setting of casing and the
completion attempt. Such election, when made, shall include consent to all
necessary expenditures for the completing and equipping of such well, including
necessary tankage and/or surface facilities. Failure of any party receiving
such notice to reply within the period above fixed shall constitute an election
by that party not to participate in the cost of the completion attempt. If one
or more, but less than all of the parties, elect to set pipe and to attempt a
completion, the provisions of Article VI.B.2. hereof (the phrase "reworking,
deepening or plugging back" as contained in Article VI.B.2. shall be deemed to
include "completing") shall apply to the operations thereafter conducted by
less than all parties.

2. Rework or Plug Back: Without the consent of all parties, no well
shall be reworked or plugged back except a well reworked or plugged back
pursuant to the provisions of Article VI.B.2. of this agreement. Consent to
the reworking or plugging back of a well shall include all necessary
expenditures in conducting such operations and completing and equipping of said
well, including necessary tankage and/or surface facilities.

3. Other Operations: Without the consent of all parties, Operator shall
not undertake any single project reasonably estimated to require an expenditure
in excess of Fifteen thousand Dollars ($15,000.00) except in connection with a
well, the drilling, reworking, deepening, completing, recompleting, or plugging
back of which has been previously authorized by or pursuant to this agreement;
provided, however, that, in case of explosion, fire, flood or other sudden
emergency, whether of the same or different nature, Operator may take such
steps and incur such expenses as in its opinion are required to deal with the
emergency to safeguard life and property but Operator, as promptly as possible,
shall report the emergency to the other parties. If Operator prepares an
authority for expenditure (AFE) for its own use, Operator shall furnish any
Non-Operator so requesting an information copy thereof for any single project
costing in excess of Fifteen thousand Dollars ($15,000.00) but less than the
amount first set forth above in this paragraph.

E. RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES:

Rentals, shut-in well payments and minimum royalties which may be
required under the terms of any lease shall be paid by the party or parties who
subjected such lease to this agreement at its or their expense. In the event
two or more parties own and have contributed interests in the same lease to
this agreement, such parties may designate one of such parties to make said
payments for and on behalf of all such parties. Any party may request, and
shall be entitled to receive, proper evidence of all such payments. In the
event of failure to make proper payment of any rental, shut-in well payment or
minimum royalty through mistake or oversight where such payment is required to
continue the lease in force, any loss which results from such non-payment shall
be borne in accordance with the provisions of Article IV.B.2.

Operator shall notify Non-Operator of the anticipated completion of a
shut-in gas well, or the shutting in or return to production of a producing
gas well, at least five (5) days (excluding Saturday, Sunday and legal
holidays), or at the earliest opportunity permitted by circumstances, prior to
taking such action, but assumes no liability for failure to do so. In the event
of failure by Operator to so notify Non-Operator, the loss of any lease
contributed hereto by Non-Operator for failure to make timely payments of any
shut-in well payment shall be borne jointly by the parties hereto under the
provisions of Article IV.B.3.

F. TAXES:

Beginning with the first calendar year after the effective date hereof,
Operator shall render for ad valorem taxation all property subject to this
agreement which by law should be rendered for such taxes, and it shall pay all
such taxes assessed thereon before they become delinquent. Prior to the
rendition date, each Non-Operator shall furnish Operator information as to
burdens (to include, but not be limited to, royalties, overriding royalties and
production payments) oil leases and oil and gas interests contributed by such
Non-Operator. If the assessed valuation of any leasehold estate is reduced by
reason of its being subject to outstanding excess royalties, overriding
royalties or production payments, the reduction in ad valorem taxes resulting
therefrom shall inure to the benefit of the owner or owners of such leasehold
estate, and Operator shall adjust the charge to such owner or owners so as to
reflect the benefit of such reduction. If the ad valorem taxes are based in
whole or in part upon separate valuations of each party's working interest,
then notwithstanding anything to the contrary herein, charges to the joint
account shall be made and paid by the parties hereto in accordance with the tax
value generated by each party's working interest. Operator shall bill the other
parties for their proportionate shares of all tax payments in the manner
provided in Exhibit "C".

If Operator considers any tax assessment improper, Operator may, at its
discretion, protest within the time and manner prescribed by law, and prosecute
the protest to a final determination, unless all parties agree to abandon the
protest prior to final determination. During the pendency of administrative or
judicial proceedings, Operator may elect to pay, under protest, all such taxes
any interest and penalty. When any such protested assessment shall have been
finally determined, Operator shall pay the tax for the joint account, together
with any interest and penalty accrued, and the total cost shall then be
assessed against the parties, and be paid by them, as provided in Exhibit "C".

Each party shall pay or cause to be paid all production, severance,
excise, gathering and other taxes imposed upon the production or handling of
such party's share of oil and/or gas produced under the terms of this
agreement.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VII
CONTINUED

G. INSURANCE:

At all times while operations are conducted hereunder, Operator shall
comply with the workmen's compensation law of the state where the operations
are being conducted; provided, however, that Operator may be a self-insurer for
liability under said compensation laws in which event the only charge that
shall be made to the joint account shall be as provided in Exhibit "C".
Operator shall also carry or provide insurance for the benefit of the joint
account of the parties as outlined in Exhibit "D", attached to and made a part
hereof. Operator shall require all contractors engaged in work on or for the
Contract Area to comply with the workmen's compensation law of the state where
the operations are being conducted and to maintain such other insurance as
Operator may require.

In the event automobile public liability insurance is specified in said
Exhibit "D", or subsequently receives the approval of the parties, no direct
charge shall be made by Operator for premiums paid for such insurance for
Operator's automotive equipment.

ARTICLE VIII.
ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

A. SURRENDER OF LEASES:

The leases covered by this agreement, insofar as they embrace acreage in
the Contract Area, shall not be surrendered in whole or in part unless all
parties consent thereto.

However, should any party desire to surrender its interest in any lease
or in any portion thereof, and the other parties do not agree or consent
thereto, the party desiring to surrender shall assign, without express or
implied warranty of title, all of its interest in such lease, or portion
thereof, and any well, material and equipment which may be located thereon and
any rights in production thereafter secured, to the parties not consenting to
such surrender. If the interest of the assigning party is or includes an oil
and gas interest, the assigning party shall execute and deliver to the party or
parties not consenting to such surrender an oil and gas lease covering such oil
and gas interest for a term of one (1) year and so long thereafter as oil
and/or gas is produced from the land covered thereby, such lease to be on the
form attached hereto as Exhibit "B". Upon such assignment or lease, the
assigning party shall be relieved from all obligations thereafter accruing, but
not theretofore accrued, with respect to the interest assigned or leased and
the operation of any well attributable thereto, and the assigning party shall
have no further interest in the assigned or leased premises and its equipment
and production other than the royalties retained in any lease made under the
terms of this Article. The party assignee or lessee shall pay to the party
assignor or lessor the reasonable salvage value of the latter's interest in any
wells and equipment attributable to the assigned or leased acreage. The value
of all material shall be determined in accordance with the provisions of
Exhibit "C", less the estimated cost of salvaging and the estimated cost of
plugging and abandoning. If the assignment or lease is in favor of more than
one party, the interest shall be shared by such parties in the proportions that
the interest of each bears to the total interest of all such parties.

Any assignment, lease or surrender made under this provision shall not
reduce or change the assignor's, lessor's or surrendering party's interest as
it was immediately before the assignment, lease or surrender in the balance of
the Contract Area; and the acreage assigned, leased or surrendered, and
subsequent operations thereon, shall not thereafter be subject to the terms and
provisions of this agreement.

B. RENEWAL OR EXTENSION OF LEASES:

If any party secures a renewal of any oil and gas lease subject to this
agreement, all other parties shall be notified promptly, and shall have the
right for a period of thirty (30) days following receipt of such notice in
which to elect to participate in the ownership of the renewal lease, insofar as
such lease affects lands within the Contract Area, by paying to the party who
acquired it their several proper proportionate shares of the acquisition cost
allocated to that part of such lease within the Contract Area, which shall be
in proportion to the interests held at that time by the parties in the Contract
Area.

If some, but less than all, of the parties elect to participate in the
purchase of a renewal lease, it shall be owned by the parties who elect to
participate therein, in a ratio based upon the relationship of their respective
percentage of participation in the Contract Area to the aggregate of the
percentages of participation in the Contract Area of all parties participating
in the purchase of such renewal lease. Any renewal lease in which less than all
parties elect to participate shall not be subject to this agreement.

Each party who participates in the purchase of a renewal lease shall be
given an assignment of its proportionate interest therein by the acquiring
party.

The provisions of this Article shall apply to renewal leases whether
they are for the entire interest covered by the expiring lease or cover only a
portion of its area or an interest therein. Any renewal lease taken before the
expiration of its predecessor lease, or taken or contracted for within six (6)
months after the expiration of the existing lease shall be subject to this
provision; but any lease taken or contracted for more than six (6) months after
the expiration of an existing lease shall not be deemed a renewal lease and
shall not be subject to the provisions of this agreement.

The provisions in this Article shall also be applicable to extensions of
oil and gas leases.

C. ACREAGE OR CASH CONTRIBUTIONS:

While this agreement is in force, if any party contracts for a
contribution of cash towards the drilling of a well or any other operation on
the Contract Area, such contribution shall be paid to the party who conducted
the drilling or other operation and shall be applied by it against the cost of
such drilling or other operation. If the contribution be in the form of
acreage, the party to whom the contribution is made shall promptly tender an
assignment of the acreage, without warranty of title, to the Drilling Parties
in the proportions

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE VIII
CONTINUED

said Drilling Parties shared the cost of drilling the well. Such acreage shall
become a separate Contract Area and, to the extent possible, be governed by
provisions identical to this agreement. Each party shall promptly notify all
other parties of any acreage or cash contributions it may obtain in support of
any well or any other operation on the Contract Area. The above provisions
shall also be applicable to optional rights to earn acreage outside the
Contract Area which are in support of a well drilled inside the Contract Area.

If any party contracts for any consideration relating to disposition of
such party's share of substances produced hereunder, such consideration shall
not be deemed a contribution as contemplated in this Article VIII.C.

D. MAINTENANCE OF UNIFORM INTEREST:

For the purpose of maintaining uniformity of ownership in the oil and
gas leasehold interests covered by this agreement, no party shall sell,
encumber, transfer or make other disposition of its interest in the leases
embraced within the Contract Area and in wells, equipment and production unless
such disposition covers either:

1. the entire interest of the party in all leases and equipment and
production; or

2. an equal undivided interest in all leases and equipment and
production in the Contract Area.

Every such sale, encumbrance, transfer or other disposition made by any
party shall be made expressly subject to this agreement and shall be made
without prejudice to the right of the other parties.

If, at any time the interest of any party is divided among and owned by
four or more co-owners, Operator, at its discretion, may require such co-owners
to appoint a single trustee or agent with full authority to receive notices,
approve expenditures, receive billings for and approve and pay such party's
share of the joint expenses, and to deal generally with, and with power to
bind, the co-owners of such party's interest within the scope of the
operations embraced in this agreement; however, all such co-owners shall have
the right to enter into and execute all contracts or agreements for the
disposition of their respective shares of the oil and gas produced from the
Contract Area and they shall have the right to receive, separately, payment of
the sale proceeds thereof.

E. WAIVER OF RIGHTS TO PARTITION:

If permitted by the laws of the state or states in which the property
covered hereby is located, each party hereto owning an undivided interest in
the Contract Area waives any and all rights it may have to partition and have
set aside to it in severalty its undivided interest therein.

F. PREFERENTIAL RIGHT TO PURCHASE:

Should any party desire to sell all or any part of its interests under
this agreement, or its rights and interests in the Contract Area, it shall
promptly give written notice to the other parties, with full information
concerning its proposed sale, which shall include the name and address of the
prospective purchaser (who must be ready, willing and able to purchase), the
purchase price, and all other terms of the offer. The other parties shall then
have an optional prior right, for a period of ten (10) days after receipt of
the notice, to purchase on the same terms and conditions the interest which
the other party proposes to sell; and, if this optional right is exercised, the
purchasing parties shall share the purchased interest in the proportions that
the interest of each bears to the total interest of all purchasing parties.
However, there shall be no preferential right to purchase in those cases where
any party wishes to mortgage its interests, or to dispose of its interests by
merger, reorganization, consolidation, or sale of all or substantially all of
its assets to a subsidiary or parent company or to a subsidiary of a parent
company, or to any company in which any one party owns a majority of the stock.

ARTICLE IX.
INTERNAL REVENUE CODE ELECTION

This agreement is not intended to create, and shall not be construed to
create, a relationship of partnership or an association for profit between or
among the parties hereto. Notwithstanding any provision herein that the rights
and liabilities hereunder are several and not joint or collective, or that this
agreement and operations hereunder shall not constitute a partnership, if, for
federal income tax purposes, this agreement and the operations hereunder are
regarded as a partnership, each party hereby affected elects to be excluded
from the application of all the provisions of Subchapter "K", Chapter 1,
Subtitle "A", of the Internal Revenue Code of 1954, as permitted and authorized
by Section 761 of the Code and the regulations promulgated thereunder. Operator
is authorized and directed to execute on behalf of each party hereby affected
such evidence of this election as may be required by the Secretary of the
Treasury of the United States or the Federal Internal Revenue Service,
including specifically, but not by way of limitation, all of the returns,
statements, and the data required by Federal Regulations 1.761. Should there be
any requirement that each party hereby affected give further evidence of this
election, each such party shall execute such documents and furnish such other
evidence as may be required by the Federal Internal Revenue Service or as may
be necessary to evidence this election. No such party shall give any notices or
take any other action inconsistent with the election made hereby. If any
present or future income tax laws of the state or states in which the Contract
Area is located or any future income tax laws of the United States contain
provisions similar to those in Subchapter "K", Chapter 1, Subtitle "A", of the
Internal Revenue Code of 1954, under which an election similar to that provided
by Section 761 of the Code is permitted, each party hereby affected shall make
such election as may be permitted or required by such laws. In making the
foregoing election, each such party states that the income derived by such
party from operations hereunder can be adequately determined without the
computation of partnership taxable income.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE X.
CLAIMS AND LAWSUITS

Operator may settle any single uninsured third party damage claim or
suit arising from operations hereunder if the expenditure does not exceed Five
thousand and no/100 Dollars ($5,000.00) and if the payment is in complete
settlement of such claim or suit. If the amount required for settlement exceeds
the above amount, the parties hereto shall assume and take over the further
handling of the claim or suit, unless such authority is delegated to Operator.
All costs and expenses of handling, settling, or otherwise discharging such
claim or suit shall be at the joint expense of the parties participating in the
operation from which the claim or suit arises. If a claim is made against any
party or if any party is sued on account of any matter arising from operations
hereunder over which such individual has no control because of the rights given
Operator by this agreement, such party shall immediately notify all other
parties, and the claim or suit shall be treated as any other claim or suit
involving operations hereunder.

ARTICLE XI.
FORCE MAJEURE

If any party is rendered unable, wholly or in part, by force majeure to
carry out its obligations under this agreement, other than the obligation to
make money payments, that party shall give to all other parties prompt written
notice of the force majeure with reasonably full particulars concerning it;
thereupon, the obligations of the party giving the notice, so far as they are
affected by the force majeure, shall be suspended during, but no longer than,
the continuance of the force majeure. The affected party shall use all
reasonable diligence to remove the force majeure situation as quickly as
practicable.

The requirement that any force majeure shall be remedied with all
reasonable dispatch shall not require the settlement of strikes, lockouts, or
other labor difficulty by the party involved, contrary to its wishes; how all
such difficulties shall be handled shall be entirely within the discretion of
the party concerned.

The term "force majeure", as here employed, shall mean an act of God,
strike, lockout, or other industrial disturbance, act of the public enemy, war,
blockade, public riot, lightning, fire, storm, flood, explosion, governmental
action, governmental delay, restraint or inaction, unavailability of equipment,
and any other cause, whether of the kind specifically enumerated above or
otherwise, which is not reasonably within the control of the party claiming
suspension.

ARTICLE XII.
NOTICES

All notices authorized or required between the parties and required by
any of the provisions of this agreement, unless otherwise specifically
provided, shall be given in writing by mail or telegram, postage or charges
prepaid, or by telex or telecopier and addressed to the parties to whom the
notice is given at the addresses listed on Exhibit "A". The originating notice
given under any provision hereof shall be deemed given only when received by
the party to whom such notice is directed, and the time for such party to give
any notice in response thereto shall run from the date the originating notice
is received. The second or any responsive notice shall be deemed given when
deposited in the mail or with the telegraph company, with postage or charges
prepaid, or sent by telex or telecopier. Each party shall have the right to
change its address at any time, and from time to time, by giving written notice
thereof to all other parties.

ARTICLE XIII.
TERM OF AGREEMENT

This agreement shall remain in full force and effect as to the oil and
gas leases and/or oil and gas interests subject hereto for the period of time
selected below; provided, however, no party hereto shall ever be construed as
having any right, title or interest in or to any lease or oil and gas interest
contributed by any other party beyond the term of this agreement.

[X] Option No. 1: So long as any of the oil and gas leases subject to this
agreement remain or are continued in force as to any part of the Contract Area,
whether by production, extension, renewal or otherwise.

[ ] Option No. 2: In the event the well described in Article VI.A., or any
subsequent well drilled under any provision of this agreement, results in
production of oil and/or gas in paying quantities, this agreement shall
continue in force so long as any such well or wells produce, or are capable of
production, and for an additional period of _____ days from cessation of all
production; provided, however, if, prior to the expiration of such additional
period, one or more of the parties hereto are engaged in drilling, reworking,
deepening, plugging back, testing or attempting to complete a well or wells
hereunder, this agreement shall continue in force until such operations have
been completed and if production results therefrom, this agreement shall
continue in force as provided herein. In the event the well described in
Article VI.A., or any subsequent well drilled hereunder, results in a dry hole,
and no other well is producing, or capable of producing oil and/or gas from the
Contract Area, this agreement shall terminate unless drilling, deepening,
plugging back or reworking operations are commenced within _____ days from the
date of abandonment of said well.

It is agreed, however, that the termination of this agreement shall not
relieve any party hereto from any liability wnich has accrued or attached prior
to the date of such termination.

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE XIV.
COMPLIANCE WITH LAWS AND REGULATIONS

A. LAWS, REGULATIONS AND ORDERS:

This agreement shall be subject to the conservation laws of the state in
which the Contract Area is located, to the valid rules, regulations, and orders
of any duly constituted regulatory body of said state; and to all other
applicable federal, state, and local laws, ordinances, rules, regulations, and
orders.

B. GOVERNING LAW:

This agreement and all matters pertaining thereto, including, but not
limited to, matters of performance, non-performance, breach, remedies,
procedures, rights, duties and interpretation or construction, shall be
governed and determined by the law of the state in which the Contract Area is
located. If the Contract Area is in two or more states, the law of the state of
________________ shall govern.

C. REGULATORY AGENCIES:

Nothing herein contained shall grant, or be construed to grant, Operator
the right or authority to waive or release any rights, privileges, or
obligations which Non-Operators may have under federal or state laws or under
rules, regulations or orders promulgated under such laws in reference to oil,
gas and mineral operations, including the location, operation, or production of
wells, on tracts offsetting or adjacent to the Contract Area.

With respect to operations hereunder, Non-Operators agree to release
Operator from any and all losses, damages, injuries, claims and causes action
arising out of, incident to or resulting directly or indirectly from Operator's
interpretation or application of rules, rulings, regulations or orders of the
Department of Energy or predecessor or Successor agencies to the extent such
interpretation or application was made in good faith. Each Non-Operator further
agrees to reimburse Operator for any amounts applicable to such Non-Operator's
share of production that Operator may be required to refund, rebate or pay as
a result of such an incorrect interpretation or application, together with
interest and penalties thereon owing by Operator as a result of such incorrect
interpretation or application.

Non-Operators authorize Operator to prepare and submit such documents as
may be required to be submitted to the purchaser of any crude oil sold
hereunder or to any other person or entity pursuant to the requirements of the
"Crude Oil Windfall Profit Tax Act of 1980", as same may be amended from time
to time ("Act"), and any valid regulations or rules which may be issued by the
Treasury Department from time to time pursuant to said Act. Each party hereto
agrees to furnish any and all certifications or other information which is
required to be furnished by said Act in a timely manner and in sufficient
detail to permit compliance with said Act.

ARTICLE XV.
OTHER PROVISIONS

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982

ARTICLE XVI.
MISCELLANEOUS

This agreement shall be binding upon and shall inure to the benefit of
the parties hereto and to their respective heirs, devisees, legal
representatives, successors and assigns.

This instrument may be executed in any number of counterparts, each of
which shall be considered an original for all purposes.

IN WITNESS WHEREOF, this agreement shall be effective as of 1st day of
May, 1996.

OPERATOR

ATTEST: BLACKJACK OIL & GAS, INC.

/s/ KAREN BEAMAN /s/ GARY FOSTER
- ------------------------------ ------------------------------
Karen Beaman, Secretary Gary Foster, President

NON-OPERATORS

NATIONAL ENERGY RESOURCES, INC.

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

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<PAGE> 19
COPAS - 1984 - ONSHORE
Recommended by the Council
[LOGO] 601, Box 800 of Petroleum Accountants
TULSA OK 74101 Societies

EXHIBIT "C"

Attached to and made a part of that certain Operating Agreement dated May 1,
1996 covering Oklahoma, Texas, and Kansas properties.

ACCOUNTING PROCEDURE

JOINT OPERATIONS

I. GENERAL PROVISIONS

1. DEFINITIONS

"Joint Property" shall mean the real and personal property subject to
the agreement to which this Accounting Procedure is attached.

"Joint Operations" shall mean all operations necessary or proper for the
development, operation, protection and maintenance of the Joint
Property.

"Joint Account" shall mean the account showing the charges paid and
credits received in the conduct of the Joint Operations and which are to
be shared by the Parties.

"Operator" shall mean the party designated to conduct the Joint
Operations.

"Non-Operators" shall mean the Parties to this agreement other than the
Operator.

"Parties" shall mean Operator and Non-Operators.

"First Level Supervisors" shall mean those employees whose primary
function in Joint Operations is the direct supervision of other
employees and/or contract labor directly employed on the Joint Property
in a field operating capacity.

"Technical Employees" shall mean those employees having special and
specific engineering, geological or other professional skills, and whose
primary function in Joint Operations is the handling of specific
operating conditions and problems for the benefit of the Joint Property.

"Personal Expenses" shall mean travel and other reasonable reimbursable
expenses of Operator's employees.

"Material" shall mean personal property, equipment or supplies acquired
or held for use on the Joint Property.

"Controllable Material" shall mean Material which at the time is so
classified in the Material Classification Manual as most recently
recommended by the Council of Petroleum Accountants Societies.

2. STATEMENT AND BILLINGS

Operator shall bill Non-Operators on or before the last day of each
month for their proportionate share of the Joint Account for the
preceding month. Such bills will be accompanied by statements which
identify the authority for expenditure, lease or facility, and all
charges and credits summarized by appropriate classifications of
investment and expense except that items of Controllable Material and
unusual charges and credits shall be separately identified and fully
described in detail.

3. ADVANCES AND PAYMENTS BY NON-OPERATORS

A. Unless otherwise provided for in the agreement, the Operator may
require the Non-Operators to advance their share of estimated cash
outlay for the succeeding month's operation within fifteen (15)
days after receipt of the billing or by the first day of the month
for which the advance is required, whichever is later. Operator
shall adjust each monthly billing to reflect advances received from
the Non-Operators.

B. Each Non-Operator shall pay its proportion of all bills within
fifteen (15) days after receipt. If payment is not made within such
time, the unpaid balance shall bear interest monthly at the prime
rate in effect at 1% on the first day of the month in which
delinquency occurs plus 1% or the maximum contract rate permitted
by the applicable usury laws in the state in which the Joint
Property is located, whichever is the lesser, plus attorney's fees,
court costs, and other costs in connection with the collection of
unpaid amounts.

4. ADJUSTMENTS

Payment of any such bills shall not prejudice the right of any
Non-Operator to protest or question the correctness thereof; provided,
however, all bills and statements rendered to Non-Operators by Operator
during any calendar year shall conclusively be presumed to be true and
correct after twenty-four (24) months following the end of any such
calendar year, unless within the said twenty-four (24) month period a
Non-Operator takes written exception thereto and makes claim on Operator
for adjustment. No adjustment favorable to Operator shall be made unless
it is made within the same prescribed period. The provisions of this
paragraph shall not prevent adjustments resulting from a physical
inventory of Controllable Material as provided for in Section V.

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5. AUDITS

A. A Non-Operator, upon notice in writing to Operator and all other
Non-Operators, shall have the right to audit Operator's accounts
and records relating to the Joint Account for any calendar year
within the twenty-four (24) month period following the end of such
calendar year; provided, however, the making of an audit shall not
extend the time for the taking of written exception to and the
adjustments of accounts as provided for in Paragraph 4 of this
Section I. Where there are two or more Non-Operators, the
Non-Operators shall make every reasonable effort to conduct a joint
audit in a manner which will result in a minimum of inconvenience
to the Operator. Operator shall bear no portion of the
Non-Operators' audit cost incurred under this paragraph unless
agreed to by the Operator. The audits shall not be conducted more
than once each year without prior approval of Operator, except upon
the resignation or removal of the Operator, and shall be made at
the expense of those Non-Operators approving such audit.

B. The Operator shall reply in writing to an audit report within 180
days after receipt of such report.

6. APPROVAL BY NON-OPERATORS

Where an approval or other agreement of the Parties or Non-Operators is
expressly required under other sections of this Accounting Procedure and
if the agreement to which this Accounting Procedure is attached contains
no contrary provisions in regard thereto, Operator shall notify all
Non-Operators of the Operator's proposal, and the agreement or approval
of a majority in interest of the Non-Operators shall be controlling on
all Non-Operators.

II. DIRECT CHARGES

Operator shall charge the Joint Account with the following items:

1. ECOLOGICAL AND ENVIRONMENTAL

Costs incurred for the benefit of the Joint Property as a result of
governmental or regulatory requirements to satisfy environmental
considerations applicable to the Joint Operations. Such costs may
include surveys of an ecological or archaeological nature and pollution
control procedures as required by applicable laws and regulations.

2. RENTALS AND ROYALTIES

Lease rentals and royalties paid by Operator for the Joint Operations.

3. LABOR

A. (1) Salaries and wages of Operator's field employees directly
employed on the Joint Property in the conduct of Joint
Operations.

(2) Salaries of First Level Supervisors in the field.

(3) Salaries and wages of Technical Employees directly employed on
the Joint Property if such charges are excluded from the
overhead rates.

(4) Salaries and wages of Technical Employees either temporarily
or permanently assigned to and directly employed in the
operation of the Joint Property if such charges are excluded
from the overhead rates.

B. Operator's cost of holiday, vacation, sickness and disability
benefits and other customary allowances paid to employees whose
salaries and wages are chargeable to the Joint Account under
Paragraph 3A of this Section II. Such costs under this Paragraph 3B
may be charged on a "when and as paid basis" or by "percentage
assessment" on the amount of salaries and wages chargeable to the
Joint Account under Paragraph 3A of this Section II. If percentage
assessment is used, the rate shall be based on the Operator's cost
experience.

C. Expenditures or contributions made pursuant to assessments imposed
by governmental authority which are applicable to Operator's costs
chargeable to the Joint Account under Paragraphs 3A and 3B of this
Section II.

D. Personal Expenses of those employees whose salaries and wages are
chargeable to the joint Account under Paragraph 3A of this Section
II.

4. EMPLOYEE BENEFITS

Operator's current costs of established plans for employees' group life
insurance, hospitalization, pension, retirement, stock purchase, thrift,
bonus, and other benefit plans of a like nature, applicable to
Operator's labor cost chargeable to the Joint Account under Paragraphs
3A and 3B of this Section II shall be Operator's actual cost not to
exceed the percent most recently recommended by the Council of Petroleum
Accountants Societies.

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5. MATERIAL

Material purchased or furnished by Operator for use on the Joint
Property as provided under Section IV. Only such Material shall be
purchased for or transferred to the Joint Property as may be required
for immediate use and is reasonably practical and consistent with
efficient and economical operations. The accumulation of surplus stocks
shall be avoided.

6. TRANSPORTATION

Transportation of employees and Material necessary for the Joint
Operations but subject to the following limitations:

A. If Material is moved to the Joint Property from the Operator's
warehouse or other properties, no charge shall be made to the Joint
Account for a distance greater than the distance from the nearest
reliable supply store where like material is normally available or
railway receiving point nearest the Joint Property unless agreed to
by the Parties.

B. If surplus Material is moved to Operator's warehouse or other
storage point, no charge shall be made to the Joint Account for a
distance greater than the distance to the nearest reliable supply
store where like material is normally available, or railway
receiving point nearest the Joint Property unless agreed to by the
Parties. No charge shall be made to the Joint Account for moving
Material to other properties belonging to Operator, unless agreed
to by the Parties.

C. In the application of subparagraphs A and B above, the option to
equalize or charge actual trucking cost is available when the
actual charge is $400 or less excluding accessorial charges. The
$400 will be adjusted to the amount most recently recommended by
the Council of Petroleum Accountants Societies.

7. SERVICES

The cost of contract services, equipment and utilities provided by
outside sources, except services excluded by Paragraph 10 of Section II
and Paragraph i, ii, and iii, of Section III. The cost of professional
consultant services and contract services of technical personnel
directly engaged on the Joint Property if such charges are excluded from
the overhead rates. The cost of professional consultant services or
contract services of technical personnel not directly engaged on the
Joint Property shall not be charged to the Joint Account unless
previously agreed to by the Parties.

9. DAMAGES AND LOSSES TO JOINT PROPERTY

All costs or expenses necessary for the repair or replacement of Joint
Property made necessary because of damages or losses incurred by fire,
flood, storm, theft, accident, or other cause, except those resulting
from Operator's gross negligence or willful misconduct. Operator shall
furnish Non-Operator written notice of damages or losses incurred as
soon as practicable after a report thereof has been received by
Operator.

10. LEGAL EXPENSE

Expense of handling, investigating and settling litigation or claims,
discharging of liens, payment of judgements and amounts paid for
settlement of claims incurred in or resulting from operations under the
agreement or necessary to protect or recover the Joint Property, except
that no charge for services of Operator's legal staff or fees or expense
of outside attorneys shall be made unless previously agreed to by the
Parties. All other legal expense is considered to be covered by the
overhead provisions of Section III unless otherwise agreed to by the
Parties, except as provided in Section I, Paragraph 3.

11. TAXES

All taxes of every kind and nature assessed or levied upon or in
connection with the Joint Property, the operation thereof, or the
production therefrom, and which taxes have been paid by the Operator for
the benefit of the Parties. If the ad valorem taxes are based in whole
or in part upon separate valuations of each party's working interest,
then notwithstanding anything to the contrary herein, charges to the
Joint Account shall be made and paid by the Parties hereto in accordance
with the tax value generated by each party's working interest.

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- -------------------------------------------------------------------------- COPAS

12. INSURANCE

Net premiums paid for insurance required to be carried for the Joint
Operations for the protection of the Parties. In the event Joint
Operations are conducted in a state in which Operator may act as
self-insurer for Worker's Compensation and/or Employers Liability under
the respective state's laws, Operator may, at its election, include the
risk under its self-insurance program and in that event, Operator shall
include a charge at Operator's cost not to exceed manual rates.

13. ABANDONMENT AND RECLAMATION

Costs incurred for abandonment of the Joint Property, including costs
required by governmental or other regulatory authority.

14. COMMUNICATIONS

Cost of acquiring, leasing, installing, operating, repairing and
maintaining communication systems, including radio and microwave
facilities directly serving the Joint Property. In the event
communication facilities/systems serving the Joint Property are Operator
owned, charges to the Joint Account shall be made as provided in
Paragraph 8 of this Section II.

15. OTHER EXPENDITURES

Any other expenditure not covered or dealt with in the foregoing
provisions of this Section II, or in Section III and which is of direct
benefit to the Joint Property and is incurred by the Operator in the
necessary and proper conduct of the Joint Operations.

III. OVERHEAD

1. Overhead - Drilling and Producing Operations

i. As compensation for administrative, supervision, office services
and warehousing costs, Operator shall charge drilling and producing
operations on either:

(X) Fixed Rate Basis, Paragraph 1A, or
( ) Percentage Basis, Paragraph 1B

Unless otherwise agreed to by the Parties, such charge shall be in
lieu of costs and expenses of all offices and salaries or wages
plus applicable burdens and expenses of all personnel, except those
directly chargeable under Paragraph 3A, Section II. The cost and
expense of services from outside sources in connection with matters
of taxation, traffic, accounting or matters before or involving
governmental agencies shall be considered as included in the
overhead rates provided for in the above selected Paragraph of this
Section III unless such cost and expense are agreed to by the
Parties as a direct charge to the Joint Account.

ii. The salaries, wages and Personal Expenses of Technical Employees
and/or the cost of professional consultant services and contract
services of technical personnel directly employed on the Joint
Property:

( ) shall be covered by the overhead rates, or
(X) shall not be covered by the overhead rates.

iii. The salaries, wages and Personal Expenses of Technical Employees
and/or costs of professional consultant services and contract
services of technical personnel either temporarily or permanently
assigned to and directly employed in the operation of the Joint
Property:

( ) shall be covered by the overhead rates, or
(X) shall not be covered by the overhead rates.

A. Overhead - Fixed Rate Basis

(1) Operator shall charge the Joint Account at the following rates
per well per month:

Drilling Well Rate $N/A
(Prorated for less than a full month)

Producing WELL Rate $350.00 per month

(2) Application of Overhead - Fixed Rate Basis shall be as
follows:

(a) Drilling Well Rate

(1) Charges for drilling wells shall begin on the date
the well is spudded and terminate on the date the
drilling rig, completion rig, or other units used
in completion of the well is released, whichever

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Societies

is later, except that no charge shall be made
during suspension of drilling or completion
operations for fifteen (15) or more consecutive
calendar days.

(2) Charges for wells undergoing any type of workover
or recompletion for a period of five (5)
consecutive work days or more shall be made at the
drilling well rate. Such charges shall be applied
for the period from date workover operations, with
rig or other units used in workover, commence
through date of rig or other unit release, except
that no charge shall be made during suspension of
operations for fifteen (15) or more consecutive
calendar days.

(b) Producing Well Rates

(1) An active well either produced or injected into for
any portion of the month shall be considered as a
one-well charge for the entire month.

(2) Each active completion in a multi-completed well in
which production is not commingled down hole shall
be considered as a one-well charge providing each
completion is considered a separate well by the
governing regulatory authority.

(3) An inactive gas well shut in because of
overproduction or failure of purchaser to take the
production shall be considered as a one-well charge
providing the gas well is directly connected to a
permanent sales outlet.

(4) A one-well charge shall be made for the month in
which plugging and abandonment operations are
completed on any well. This one-well charge shall
be made whether or not the well has produced except
when drilling well rate applies.

(5) All other inactive wells (including but not limited
to inactive wells covered by unit allowable, lease
allowable, transferred allowable, etc.) shall not
qualify for an overhead charge.

(3) The well rates shall be adjusted as of the first day of April each
year following the effective date of the agreement to which this
Accounting Procedure is attached. The adjustment shall be computed
by multiplying the rate currently in use by the percentage increase
or decrease in the average weekly earnings of Crude Petroleum and
Gas Production Workers for the last calendar year compared to the
calendar year preceding as shown by the index of average weekly
earnings of Crude Petroleum and Gas Production Workers as published
by the United States Department of Labor, Bureau of Labor
Statistics, or the equivalent Canadian index as published by
Statistics Canada, as applicable. The adjusted rates shall be the
rates currently in use, plus or minus the computed adjustment.

2. OVERHEAD - MAJOR CONSTRUCTION

To compensate Operator for overhead costs incurred in the construction
and installation of fixed assets, the expansion of fixed assets, and any
other project clearly discernible as a fixed asset required for the
development and operation of the Joint Property, Operator shall either
negotiate a rate prior to the beginning of construction, or shall charge
the Joint

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4. AMENDMENT OF RATES

The overhead rates provided for in this Section III may be amended from
time to time only by mutual agreement between the Parties hereto if, in
practice, the rates are found to be insufficient or excessive.

IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS

Operator is responsible for Joint Account Material and shall make proper and
timely charges and credits for all Material movements affecting the Joint
Property. Operator shall provide all Material for use on the Joint Property;
however, at Operator's option, such Material may be supplied by the
Non-Operator. Operator shall make timely disposition of idle and/or surplus
Material, such disposal being made either through sale to Operator or
Non-Operator, division in kind, or sale to outsiders. Operator may purchase,
but shall be under no obligation to purchase, interest of Non-Operators in
surplus condition A or B Material. The disposal of surplus Controllable
Material not purchased by the Operator shall be agreed to by the Parties.

1. PURCHASES

Material purchased shall be charged at the price paid by Operator after
deduction of all discounts received. In case of Material found to be
defective or returned to vendor for any other reasons, credit shall be
passed to the Joint Account when adjustment has been received by the
Operator.

2. TRANSFERS AND DISPOSITIONS

Material furnished to the Joint Property and Material transferred from
the Joint Property or disposed of by the Operator, unless otherwise
agreed to by the Parties, shall be priced on the following basis
exclusive of cash discounts:

A. New Material (Condition A)

(1) Tubular Goods Other than Line Pipe

(a) Tubular goods, sized 2-3/8 inches OD and larger, except
line pipe, shall be priced at Eastern mill published
carload base prices effective as of date of movement plus
transportation cost using the 80,000 pound carload weight
basis to the railway receiving point nearest the Joint
Property for which published rail rates for tubular goods
exist. If the 80,000 pound rail rate is not offered, the
70,000 pound or 90,000 pound rail rate may be used.
Freight charges for tubing will be calculated from
Lorain, Ohio and casing from Youngstown, Ohio.

(b) For grades which are special to one mill only, prices
shall be computed at the mill base of that mill plus
transportation cost from that mill to the railway
receiving point nearest the Joint Property as provided
above in Paragraph 2.A.(1)(a). For transportation cost
from points other than Eastern mills, the 30,000

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Societies

pound Oil Field Haulers Association interstate truck rate
shall be used.

(c) Special end finish tubular goods shall be priced at the
lowest published out-of-stock price, f.o.b. Houston,
Texas, plus transportation cost, using Oil Field Haulers
Association interstate 30,000 pound truck rate, to the
railway receiving point nearest the Joint Property.

(d) Macaroni tubing (size less than 2-3/8% inch OD) shall be
priced at the lowest published out-of-stock prices f.o.b.
the supplier plus transportation costs, using the Oil
Field Haulers Association interstate truck rate per
weight of tubing transferred, to the railway receiving
point nearest the Joint Property.

(2) Line Pipe

(a) Line pipe movements (except size 24 inch OD and larger
with walls 3/4 inch and over) 30,000 pounds or more shall
be priced under provisions of tubular goods pricing in
Paragraph A.(1)(a) as provided above. Freight charges
shall be calculated from Lorain, Ohio.

(b) Line pipe movements (except size 24 inch OD and larger
with walls 3/4 inch and over) less than 30,000 pounds
shall be priced at Eastern mill published carload base
prices effective as of date of shipment, plus 20 percent,
plus transportation costs based on freight rates as set
forth under provisions of tubular goods pricing in
Paragraph A.(1)(a) as provided above. Freight charges
shall be calculated from Lorain, Ohio.

(c) Line pipe 24 inch OD and over and 3/4 inch wall and
larger shall be priced f.o.b. the point of manufacture at
current new published prices plus transportation cost to
the railway receiving point nearest the Joint Property.

(d) Line pipe, including fabricated line pipe, drive pipe and
conduit not listed on published price lists shall be
priced at quoted prices plus freight to the railway
receiving point nearest the Joint Property or at prices
agreed to by the Parties.

(3) Other Material shall be priced at the current new price, in effect
at date of movement, as listed by a reliable supply store nearest
the Joint Property, or point of manufacture, plus transportation
costs, if applicable, to the railway receiving point nearest the
Joint Property.

(4) Unused new Material, except tubular goods, moved from the Joint
Property shall be priced at the current new price, in effect on
date of movement, as listed by a reliable supply store nearest the
Joint Property, or point of manufacture, plus transportation costs,
if applicable, to the railway receiving point nearest the Joint
Property. Unused new tubulars will be priced as provided above in
Paragraph 2.A.(l) and (2).

B. Good Used Material (Condition B)

Material in sound and serviceable condition and suitable for reuse
without reconditioning:

(1) Material moved to the Joint Property

At seventy-five percent (75%) of current new price, as determined
by Paragraph A.

(2) Material used on and moved from the Joint Property

(a) At seventy-five percent (75%) of current new price, as
determined by Paragraph A, if Material was originally
charged to the Joint Account as new Material or

(b) At sixty-five percent (65%) of current new price, as
determined by Paragraph A, if Material was originally
charged to the Joint Account as used Material.

(3) Material not used on and moved from the Joint Property

At seventy-five percent (75%) of current new price as
determined by Paragraph A.

The cost of reconditioning, if any, shall be absorbed by the
transferring property.

C. Other Used Material

(1) Condition C

Material which is not in sound and serviceable condition and
not suitable for its original function until after
reconditioning shall be priced at fifty percent (50%) of
current new price as determined by Paragraph A. The cost of
reconditioning shall be charged to the receiving property,
provided Condition C value plus cost of reconditioning does
not exceed Condition B value.

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(2) Condition D

Material, excluding junk, no longer suitable for its original
purpose, but usable for some other purpose shall be priced on
a basis commensurate with its use. Operator may dispose of
Condition D Material under procedures normally used by
Operator without prior approval of Non-Operators.

(a) Casing, tubing, or drill pipe used as line pipe shall be
priced as Grade A and B seamless line pipe of comparable
size and weight. Used casing, tubing or drill pipe
utilized as line pipe shall be priced at used line pipe
prices.

(b) Casing, tubing or drill pipe used as higher pressure
service lines than standard line pipe, e.g. power oil
lines, shall be priced under normal pricing procedures
for casing, tubing, or drill pipe. Upset tubular goods
shall be priced on a non upset basis.

(3) Condition E

Junk shall be priced at prevailing prices. Operator may
dispose of Condition E Material under procedures normally
utilized by Operator without prior approval of Non-Operators.

D. Obsolete Material

Material which is serviceable and usable for its original function
but condition and/or value of such Material is not equivalent to
that which would justify a price as provided above may be specially
priced as agreed to by the Parties. Such price should result in
the Joint Account being charged with the value of the service
rendered by such Material.

E. Pricing Conditions

(1) Loading or unloading costs may be charged to the Joint Account
at the rate of twenty-five cents (25 cents per hundred weight
on all tubular goods movements, in lieu of actual loading or
unloading costs sustained at the stocking point. The above
rate shall be adjusted as of the first day of April each year
following January 1, 1985 by the same percentage increase or
decrease used to adjust overhead rates in Section III,
Paragraph I.A.(3). Each year, the rate calculated shall be
rounded to the nearest cent and shall be the rate in effect
until the first day of April next year. Such rate shall be
published each year by the Council of Petroleum Accountants
Societies.

(2) Material involving erection costs shall be charged at
applicable percentage of the current knocked-down price of new
Material.

3. PREMIUM PRICES

Whenever Material is not readily obtainable at published or listed
prices because of national emergencies, strikes or other unusual causes
over which the Operator has no control, the Operator may charge the
Joint Account for the required Material at the Operator's actual cost
incurred in providing such Material, in making it suitable for use, and
in moving it to the Joint Property; provided notice in writing is
furnished to Non-Operators of the proposed charge prior to billing
Non-Operators for such Material. Each Non-Operator shall have the right,
by so electing and notifying Operator within ten days after receiving
notice from Operator, to furnish in kind all or part of his share of
such Material suitable for use and acceptable to Operator.

4. WARRANTY OF MATERIAL FURNISHED BY OPERATOR

Operator does not warrant the Material furnished. In case of defective
Material, credit shall not be passed to the Joint Account until
adjustment has been received by Operator from the manufacturers or their
agents.

V. INVENTORIES

The Operator shall maintain detailed records of Controllable Material.

1. PERIODIC INVENTORIES, NOTICE AND REPRESENTATION

At reasonable intervals, inventories shall be taken by Operator of the
Joint Account Controllable Material. Written notice of intention to
take inventory shall be given by Operator at least thirty (30) days
before any inventory is to begin so that Non-Operators may be
represented when any inventory is taken. Failure of Non-Operators to be
represented at an inventory shall bind Non-Operators to accept the
inventory taken by Operator.

2. RECONCILIATION AND ADJUSTMENT OF INVENTORIES

Adjustments to the Joint Account resulting from the reconciliation of a
physical inventory shall be made within six months following the taking
of the inventory. Inventory adjustments shall be made by Operator to the
Joint Account for

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overages and shortages, but, Operator shall be held accountable only for
shortages due to lack of reasonable diligence.

3. SPECIAL INVENTORIES

Special inventories may be taken whenever there is any sale, change of
interest, or change of Operator in the Joint Property. It shall be the
duty of the party selling to notify all other Parties as quickly as
possible after the transfer of interest takes place. In such cases, both
the seller and the purchaser shall be governed by such inventory. In
cases involving a change of Operator, all Parties shall be governed by
such inventory.

4. EXPENSE OF CONDUCTING INVENTORIES

A. The expense of conducting periodic inventories shall not be charged
to the Joint Account unless agreed to by the Parties.

B. The expense of conducting special inventories shall be charged to
the Parties requesting such inventories, except inventories
required due to change of Operator shall be charged to the Joint
Account.

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<PAGE> 1

NATIONAL ENERGY RESOURCES, INC.
21800 Burbank Blvd., Suite 100
Woodland Hills, California 91364

June 11, 1996

Mr. Gary Foster
Blackjack Oil & Gas, Inc.
1633 West Garriott Road, Suite D
Enid, Oklahoma 73703

Re: Letter of Intent

Dear Mr. Foster:

Discussions have been held between you and the undersigned concerning
the sale of certain oil and gas properties and production equipment (the
"Properties") by Blackjack Oil & Gas, Inc. (the "Seller") to C.D. National
Energy Resources, Inc. (the "Buyer"). This letter sets forth the terms and
conditions of our proposal to purchase the Properties from the Seller.

I. PROPERTIES PURCHASE

Attached to this Letter of Intent as Exhibit "A" and made a part
hereof is a description by lease designation of the producing oil and gas
properties which Buyer is willing to purchase from Seller. The offer to
purchase is made conditioned on the representations Seller has made that the
lease acreage, working interest being transferred and the net revenue interest
for each property is as represented on Exhibit "A". The producing properties
also include all of the production and other equipment now on the wells.

II. PURCHASE PRICE AND ADJUSTMENTS

Buyer is offering to pay the sum of $430,000 at closing for the
Properties as defined above subject to the following adjustments and the
conditions set forth below.

The purchase price shall be adjusted for the following: (a) any
differences in the working interest percentages and net revenue interest
percentages from those set forth in Exhibit "A"; (b) any changes in the
producing well equipment from that listed by exhibit; (c) any changes in the
joint interest billing receivables and suspense monies from those represented
by Seller; and (d) any gas balancing adjustments or contract balancing
adjustments as provided for below.

III. TITLE

Title to the Properties will be transferred free and clear of all
title defects, liens, claims, mortgages and other encumbrances. The
assignments of the leases for the producing properties will be with warranty.
The bill of sale for the equipment shall include a warranty as to title as
well. Seller will provide Buyer at Seller's cost updated title opinions on the
producing properties. Acceptance of title shall be in the sole discretion of
Buyer, not to be unreasonably withheld.
<PAGE> 2
Mr. Gary Foster
June 11, 1996
Page 2

IV. OPERATIONS AND CONTRACTS

Seller will retain operations of the Properties following closing.
Prior to closing, all gas balancing adjustments will be made for over
production of the Properties as well as any gas contract balancing for royalty
payment deficiencies, if any. All gas and other purchase contracts will be
assigned at closing.

V. PRECONDITIONS TO PURCHASE

The following items are preconditions to the purchase of your the
Properties by the Buyer:

1. A definitive purchase agreement being entered into between the parties
which outlines all of the terms and conditions of this letter of
intent.

2. That Buyers are satisfied that Properties are as represented following
examination of the information and records requested.

3. A satisfactory review and examination of the information and records
Seller regarding the Properties including but not limited to the
operating agreements, engineering and reserve reports, title reports
and opinions, gas contracts, leases, well records, accounting records
and operating statements. The purchase shall be conditioned on Buyer
finding such records acceptable and in good order to its sole
satisfaction and determination.

4. No material adverse changes in the conditions or obligations of the
Properties as determined solely by the Buyer.

VI. CLOSING

Buyer propose a closing to be effective not later than August 31, 1996
subject to the title and other requirements being met.

If the foregoing is satisfactory to you, please sign and return the
enclosed copy of this letter. I understand that this letter is merely a
statement of interest and not binding upon either you or me. However, we agree
in principle to the contents hereof and propose to proceed promptly and in good
faith to prepare a definitive agreement and conduct our investigation.

Very truly yours,

Marshall Field as President of
Energy Resources, Inc.
<PAGE> 3
Mr. Gary Foster
June 11, 1996
Page 3

Agreed to and accepted this ___ day of June, 1996 by the undersigned
on behalf of Blackjack Oil & Gas, Inc.

_______________________________
Gary Foster

<PAGE> 1
Exhibit 23 (i)

CONSENT OF COUNSEL

Robertson & Williams, Inc., a professional corporation, hereby
consents to the use of its name under the caption "VALIDITY OF SECURITIES" in
the Prospectus constituting a part of this Registration Statement.

ROBERTSON & WILLIAMS, INC.

Oklahoma City, Oklahoma
June 11, 1996

<PAGE> 1
Exhibit 23 (ii)

CONSENT OF INDEPENDENT ACCOUNTANTS

We consent to the inclusion in this Registration Statement on Form S-1
of our report dated July 31, 1995, on our audit of the financial statement of
National Energy Resources, Inc. We also consent to the reference to our firm
under the caption "EXPERTS."

MUSECK & MUSECK

New Providence, New Jersey
June 11, 1996

<PAGE> 1
Exhibit 23 (iii)

CONSENT OF PETROLEUM ENGINEERS

F. W. Elton, Inc. hereby consents to the inclusion in this
Registration Statement on Form S-1 our engineering reserve report dated April
17, 1996, and we consent to the reference to our firm under the caption
"EXPERTS.

F.W. ELTON, INC.

Enid, Oklahoma
June 11, 1996