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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------
FORM 10-K/A
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-26662
PANACO, Inc.
(Exact name of registrant as specified in its charter)

Delaware 43 - 1593374

(State or other jurisdiction of incorporation (I.R.S. Employer Identification
or organization) Number)

1050 West Blue Ridge Boulevard, PANACO Building,
Kansas City, MO 64145-1216

(Address of principal executive offices) (Zip Code)

Registrant telephone number, including area code: (816) 942 - 6300

Securities registered pursuant to Section 12(d) of the Act:
None

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 par value
(Title of Class)

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

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

The aggregate market value if the voting stock held by non-affiliates of the
registrant was approximately $73,589,180 as of March 31, 1997.

20,382,087 shares of the registrant Common Stock were outstanding as of March
31, 1997.
Documents Incorporated by Reference

None

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GLOSSARY OF SELECTED OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms
commonly used in the oil and gas industry.

"3-D seismic" means seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.

"Bank Facility" means the Company's reducing revolving bank facility with
First Union National Bank of North Carolina and Banque Paribas.

"Bbl" means a barrel of oil and condensate or natural gas liquids, being 42
U.S. gallons.

"Bcf" means billion cubic feet of natural gas.

"Bcfe" means billion cubic feet of natural gas equivalents.

"Block" means one offshore unit of lease acreage, generally 5,000 acres.

"Btu" or "British Thermal Unit" means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit.

"Condensate" means a hydrocarbon mixture that becomes liquid and separates
from natural gas when the gas is produced and is similar to crude oil.

"Developed acreage" means oil and gas acreage spaced for or assignable to
productive wells.

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

"Dry hole" means a well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well.

"Equivalent Bbls" means a measure of gas volumes representing the estimated
relative energy content of natural gas to oil, being 6 Mcf of natural gas per
Bbl of oil.

"Estimated future net revenues" means revenues from production of oil and
gas, net of all production -related taxes, lease operating expenses and capital
costs.

"Exploratory well" means a well drilled to find and produce oil or gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil and gas in another reservoir, or to extend a known reservoir.

"Farmout" means an agreement whereby the lease owner agrees to allow
another to drill a well or wells and thereby earn the right to an assignment of
a portion or all of the lease, with the original lease owner typically retaining
an overriding royalty interest and other rights to participate in the lease.

"Gross," when used with respect to acres or wells, refers to the total
acres or wells in which the Company has a working interest.

"Group 3-D seismic" means seismic procured by a group of parties or shot on
a speculative basis by a seismic company.

"MBbls" means thousands of barrels of oil.

"MBO" means one thousand barrels of oil.

"Mbtu" means one thousand Btus.

"Mcf" means thousand cubic feet of natural gas.

"Mcfe" means thousand cubic feet of natural gas equivalents.

"MMBbls" means millions of barrels of oil.

"MMBtu" means one million British Thermal Units.

"MMcf" means million cubic feet of natural gas.

"MMcfe" means million cubic feet of natural gas equivalents.

"Natural gas equivalents" means a volume, expressed in Mcf's of natural
gas, that includes not only natural gas but also liquids converted to an
equivalent quantity of natural gas on an energy equivalent basis. Equivalent gas
reserves are based on a conversion factor of 6 Mcf of gas per barrel of liquids.

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

"Net pay" means the thickness of a productive reservoir capable of
containing hydrocarbons.

"Net production" means production that is owned by the Company less
royalties and production due others.

"NGLs" means the natural gas liquids such as ethane, propane, iso-butane,
normal butane and natural gasoline that have been extracted from natural gas.

"Oil" means crude oil or condensate.

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

"Overriding royalty interest" or "ORRI" means an interest in an oil and gas
property entitling the owner to a share of oil and gas production free of costs
of exploration and production.

"Payout" means that point in time when a party has recovered monies out of
the production from a well equal to the cost of drilling and completing the well
and the cost of operating the well through that date.

"Present value of future net revenues" or "Present value of proved
reserves" means the present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with Securities
and Exchange Commission guidelines, net of estimated production and future
development costs, using prices and costs as of the date of estimation without
future escalation, except as otherwise provided by contract, without giving
effect to non-property related expenses such as general and administrative
expenses, debt service, future income tax expense and depreciation, depletion
and amortization, and discounted using an annual discount rate of 10%.

"Production costs" means costs necessary for the production of a well or
field and sale of oil and gas, including production and ad valorem taxes.

"Productive well" means a well that is producing oil or gas or that is
capable of production.

"Proprietary 3-D seismic" means seismic privately procured and owned by the
procurer.

"Proved developed nonproducing reserves" means those reserves that exist
behind the casing if existing wells or at minor depths below the present bottom
of such wells and that are expected to be produced through these wells in the
predictable future, when the cost of making such oil and gas available for
production should be relatively small compared to the cost of a new well.

"Proved developed producing reserves" means those reserves that are
expected to be produced from existing completion intervals now open for
production in existing wells.

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

"Proved reserves" means the estimated quantities of crude oil, natural gas
and natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions (i.e., prices and costs as of
the date the estimate is made). Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on escalation
based upon future conditions.

i. Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.

ii. Reserves that can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.

iii. Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified separately as
"indicated additional reserve", (B) crude oil, natural gas and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics or economic factors; (C)
crude oil, natural gas and natural gas liquids that may occur in undrilled
prospects; and (D) crude oil, natural gas and natural gas liquids that may be
recovered from oil shales, coal, gilsonite and other such sources.

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

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

"Reserves" means proved reserves.

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

"SEC 10 Value" means the present value of estimated future net revenues,
before taxes, of the specified reserves or property, determined in all material
respects in accordance with the rules and regulations of the SEC (generally
using prices and costs in effect at a fixed date and a 10% discount rate).

"Shut-in" means to close down a producing well or field temporarily for
repair, cleaning out, building up reservoir pressure, lack of a market or
similar conditions.

"Undeveloped acreage" means the oil and gas acreage on which wells have not
been drilled or to which no Proved Reserves other than Proved Undeveloped
Reserves have been attributed by independent petroleum engineers.

"Unproved properties" means the oil and gas acreage to which no Proved
Reserves have been attributed by independent petroleum engineers.

"Unproved reserves" means those reserves based on geologic and/or
engineering data similar to that used in estimates of proved reserves; but
technical, contractual, economic, or regulatory uncertainties preclude such
reserves being classified as proved. They may be estimated assuming future
economic conditions different from those prevailing at the time of the estimate.
Unproved reserves may be divided into two subclassifications: "probable" and
"possible."

"Working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain only
87.5% of the production.
Part I

Item 1. Business.

General

PANACO, Inc. (the "Company") is a Delaware corporation that was
organized in October 1991. Effective September 1, 1992, Pan Petroleum MLP, the
Company's predecessor, was merged into the Company. The Company is in the oil
and gas business, acquiring, drilling and operating offshore oil and gas
properties in the Gulf of Mexico.

Between 1984 and 1988 a total of 114 limited partnerships were
consolidated into the Company's predecessor. With the acquisition of the West
Delta Properties in 1991, the Company shifted its emphasis offshore. Additional
offshore properties were acquired in 1994, 1995 and 1996. In recent years the
Company has been disposing of numerous onshore properties. The onshore
properties presently generate less than 4% of the Company's revenues. These
onshore property sales are part of management's plan to concentrate on
properties in the Gulf of Mexico, which the Company considers to be more
profitable.

Recent Common Share Offering

On March 7, 1997, the Company completed an offering of 8,403,305 Common
Shares at $4.00 per share, $3.728 net of the underwriter's commission,
consisting of 6,000,000 shares sold by the Company and 2,403,305 shares sold by
shareholders. The Company's proceeds of $22,000,000 (net of $350,000 in offering
expenses) from the offering were used to repay $13,500,000 of its Subordinated
Notes, specifically the 1993 Subordinated Notes and the 1996 Tranche B Bridge
Loan Subordinated Notes. The remaining proceeds were temporarily paid on the
Company's reducing revolving loan and will ultimately be used for the
development of its properties and future acquisitions.

Business Strategy

The Company's objective is to enhance shareholder value through
sustained growth in its reserve base, production levels and resulting cash flows
from operations. In pursuing this objective, the Company maintains a geographic
focus in the Gulf of Mexico and identifies properties that may be acquired
preferably through negotiated transactions or, if necessary, sealed bid
transactions. The properties the Company seeks to acquire generally are
geologically complex, with multiple reservoirs, have an established production
history and are candidates for exploitation. Geologically complex fields with
multiple reservoirs are fields in which there are multiple reservoirs at
different depths and wells which penetrate more than one reservoir that have the
potential for recompletion in more than one reservoir. Once properties are
acquired, the Company focuses on reducing operating costs and implementing
production enhancements through the application of technologically advanced
production and recompletion techniques. Over the past five years,

the Company has taken advantage of opportunities to acquire interests in a
number of producing properties which fit these criteria.

Business Activities

The Company owns interests in 123 offshore wells, located offshore
Louisiana and Texas. It also owns interests in 308 onshore wells in Kansas,
Louisiana, Oklahoma and Texas, but these interests generate less than 4% of its
revenues. As of December 31, 1996, these properties, including the recently
acquired Amoco Properties and excluding the Bayou Sorrel Field which was
recently sold, contained estimated Proved Reserves of approximately 2,239,000
Bbls of oil and condensate and approximately 41,446,000 Mcf of gas and the SEC
10 Value of such Proved Reserves was approximately $113,467,000. Approximately
20% of such Proved Reserves are attributable to oil and 80% to natural gas,
based on six Mcf of gas being equivalent to one Bbl of oil. Information included
herein with respect to Proved Reserves and the SEC 10 Value thereof has been
prepared by the Company. See "Properties - Significant Proved Properties."

The Company expects to hold its producing properties until the
economically recoverable reserves attributable thereto are depleted, although
the Company may sell any of its properties if management believes that such sale
would be in the Company's best interest.

Recent Explosion and Fire

The Company experienced an explosion and fire on April 24, 1996 at Tank
Battery #3 in West Delta resulting in the fields being shut-in from April 24th,
until being returned to production on October 7, 1996. The loss of 67 days of
production in the second quarter and the entire third quarter resulted in lost
revenues of approximately $6,000,000. During the second quarter the Company
expensed $500,000 for its loss as a result of this explosion. No further losses
have been recognized or are anticipated. This $500,000 amount included $225,000
in deductibles under the Company's insurance.

The Company has spent $8,500,000 on Tank Battery #3, inclusive of the
$500,000 expensed during second quarter and has received reimbursement from its
insurance company of $3,900,000, after satisfaction of the $225,000 in
deductibles. The excess of expenditures over insurance reimbursement will be
capitalized. No additional expenditures have been made or are anticipated.

Well Operations

The Company operates 52 offshore wells and owns all of the working
interests in substantially all of those wells. The Company's 71 remaining
offshore wells are operated by third party operators, including Unocal
Corporation, Phillips Petroleum Company, Texaco, Anadarko Petroleum Corporation
and Louisiana Land and Exploration Company. Operations are conducted pursuant to
joint operating agreements that were in effect at the time the Company acquired
its interest in these properties. The Company considers these joint operating
agreements to be on terms customary within the industry. The operator of an oil
and gas property supervises production, maintains production records, employs
field personnel, and performs other functions required in the production and
administration of such property. The compensation paid to the operator for such
services customarily varies from property to property, depending on the nature,
depth, and location of the property being operated. Where properties are
operated by the Company, it generally owns all of the working interests or a
majority of the working interest in the properties. Therefore, its revenue and
expense associated with portions of properties it operates for other working
interest holders is not material.

Acquisition, Development, and Other Activities

The Company utilizes its capital budget for (a) the acquisition of
interests in other producing properties, (b) recompletions of its existing
wells, and (c) the drilling of development and exploratory wells.

In recent years, major oil companies have been selling certain offshore
properties to independent oil companies because they feel these properties do
not have the remaining reserve potential needed by a major oil company. Several
independent oil companies have acquired these offshore properties and achieved
significant success in further exploitation of these properties. Even though a
property does not meet the criteria for further development by a major oil
company, that does not mean it is lacking further exploitation potential. The
majors are simply moving further offshore into deeper water and to other
countries where they can find and produce the super-fields that fit their
criteria. Present day technology permits drilling and completing wells in water
as deep as 10,000 feet.

On October 8, 1996, the Company closed on its acquisition of interests in
six offshore fields from Amoco Production Company for $40,400,000. In
consideration for such interests, the Company issued Amoco 2,000,000 Common
Shares and paid the sum of $32,000,000 in cash. The interests acquired include
(1) a 33.3% working interest in the East Breaks 160 Field (2 Blocks) and a 33.3%
interest in the High Island 302 Field, both operated by Unocal Corporation; (2)
a 50% interest in the High Island 309 Field (2 Blocks) and a 12% interest in the
High Island 330 Field (3 Blocks), both operated by Costal Oil and Gas
Corporation; (3) a 12% interest in the High Island 474 Field (4 Blocks),
operated by Phillips Petroleum Company; and (4) a 12.5% interest in the West
Cameron 180 Field (1 Block), operated by Texaco. Current production for the
interests acquired is 623 barrels of oil per day and 10.1 MMcf per day of
natural gas. See "Properties - Amoco Acquisition."

Depending on the sales prices of oil and gas and its ability to finance
such activities, the Company may also drill exploratory wells on properties it
acquires. The Company will evaluate potential prospects to determine the
economic benefit to the Company and may drill exploratory wells if the benefit
to the Company is reasonable when measured against the risks involved.

The number and type of wells drilled by the Company will vary from period
to period depending on the amount of the capital budget available for drilling,
the cost of each well, the Company's commitment to participate in the wells
drilled on properties operated by third parties, the size of the fractional
working interest acquired by the Company in each well and the estimated
recoverable reserves attributable to each well.

Acquisitions of properties may include acquisitions of working interests,
royalty interests, net profits interests, production payments, and other forms
of direct or indirect ownership interest or interests in oil and gas production.
The Company may also acquire general or limited partner interests in general or
limited partnerships and interests in joint ventures, corporations, or other
entities that own, manage, or are formed to acquire, explore for, or develop oil
and gas properties or conduct other activities associated with the ownership of
oil and gas production. The Company may also acquire or participate in the
expansion of natural gas processing plants and natural gas transportation or
gathering systems.

The success of the Company's acquisitions will depend on (a) the Company's
ability to establish accurately the volumes of reserves and rates of future
production from producing properties being considered for acquisition and the
future net revenues attributable to reserves from such properties, taking into
account future operating costs, market prices for oil and gas, rates of
inflation, risks attendant to production of oil and gas, and a suitable return
on investment, and (b) the Company's ability to purchase properties and produce
and market oil and gas therefrom at prices and rates that over time will
generate cash flows resulting in an attractive return on the initial

investment. The Company's cash flow and return on investment will vary to the
extent that the Company's production from an acquired property is greater or
less than that estimated at the time of acquisition because of, for example, the
results of drilling or improved recovery programs, the demand for oil and gas,
or changes in the prices of oil and gas from the prices used to calculate the
purchase price for producing properties. The Company will evaluate any
economically feasible project that would enhance the value of its properties.
Such a project may involve both the acquisition of developed and undeveloped
properties and the drilling of infield wells.

The Company expects that its primary activities will continue to be
concentrated offshore in the Gulf of Mexico. The Company can, if it so chooses,
invest in any geographic area. Drilling on and production from offshore
properties often involves higher costs than does drilling on and production from
onshore properties, but the production achieved on successful wells is generally
much greater.

The Company may also seek to acquire oil and gas companies through stock
purchases, asset purchases, and purchases of interests in partnerships. The
Company intends to pay for such possible acquisitions with its own securities,
cash or any other property, or any combination of the foregoing. The consent of
the Company's lenders is required for any such purchases. See "Funding of
Business Activities - Borrowings and Obligations".

Use of 3-D Seismic Technology

The use of 3-D seismic and computer-aided exploration ("CAEX")
technology is an integral component of the Company's acquisition, exploitation,
drilling and business strategy. In general, 3-D seismic is the process of
obtaining seismic data along multiple lines and grids within a large geographic
area. 3-D seismic differs from 2-D seismic in that it provides information with
respect to multiple horizontal and vertical points within a geological formation
instead of information on a single vertical line or multiple vertical lines
within the formation. By expanding the amount of data obtained with respect to a
geological formation, the user is better able to correlate the data and obtain a
greater understanding and image of the formation. While it is impossible to
predict with certainty the specific configuration or composition of any
underground geological formation, 3-D seismic provides a mechanism by which
clearer and more accurate projected images of complex geological formations can
be obtained prior to drilling for hydrocarbons therein. In particular, 3-D
seismic delineates smaller reservoirs with greater precision than can be
obtained with 2-D seismic.

CAEX technology is the process of accumulating and analyzing the various
seismic, production and other data obtained relating to a potential prospect. In
general, the process of prospect evaluation through CAEX technology requires
inputting various 2-D and 3-D seismic data obtained with respect to a prospect,
correlating that data with historical well control and production data from
similar properties and analyzing the available data through computer programs
and modeling techniques in order to project the likely geological composition of
a prospect and potential locations of hydrocarbons. This process relies on a
comparison of actual data with respect to the prospect and historical data with
respect to the density and sonic characteristics of different types of rock
formations, hydrocarbons and other subsurface minerals, resulting in a projected
three dimensional image of the subsurface. This modeling is performed through
the use of advanced interactive computer workstations and various combinations
of available computer programs that have been developed solely for this
application.

3-D seismic and CAEX technology have been in existence since the mid
1970's; however, it was not until the late 1980's, with the development of
improved data acquisition equipment and techniques capable of gathering
significant amounts of data through a large number of channels and the
availability of improved computer technology at reasonable costs, that the
method became economically available to firms such as the Company. Prior to
that, it was the exclusive province of large multinational oil companies. The
Company owns 2-D seismic on all of its offshore properties and, owns 3-D seismic
on East Breaks Block 160 Field, High Island

304 Field, High Island 474 Field and West Delta Block 58 Field. In addition to
this proprietary 3-D seismic, much group seismic data is available on the
Companys' remaining properties. A new 3-D seismic survey will be shot by Flores
& Rucks, Inc. on the Companys' properties in West Delta. The Company owns its
own seismic processing equipment, but it also utilizes the services of outside
firms to process and interpret seismic data.

The Company believes that its application of 3-D seismic and CAEX
technology in the exploration of oil and natural gas provides it with a number
of benefits in the exploration, delineation and development process that are not
generally available to those who only use 2-D seismic data and conventional
processing methods. In particular, the Company believes that, by obtaining
clearer and more accurate projected images of underground formations through
computer modeling, the Company is able to specifically identify potential
locations of hydrocarbon accumulations based on the characteristics of the
formations and analogies made with nearby fields and formations where
hydrocarbons have been found. This enhanced data can be used to assist the
Company in eliminating prospects and prospect locations that might otherwise
have been drilled had the Company relied solely on 2-D seismic data. This data
can be used to assist the Company in identifying the perceived most desirable
location for the well to maximize the likelihood of a successful exploratory or
development well and production from the reservoir.

The Company believes that the collective application of 3-D seismic and
CAEX technology enables a much more accurate definition of the risk profile of a
prospect than was previously available using traditional exploration techniques.
To the extent the Company is successful in increasing its success rate and
reducing its dry hole costs through the use of advanced technology the Company
believes it has a competitive advantage over companies that do not use such
technology.

The Company generated a prospect in the northern portion of West Delta
Block 58 using 3-D seismic, which it farmed out to Tana Oil & Gas Corporation in
1996. Tana drilled a successful well to 12,800 feet which encountered 85 feet of
net pay and produces in excess of 15,000 Mcf per day. The Company retained a
5.833% overriding royalty interest in the farmout. Three of the fields in the
Amoco Acquisition have proprietary 3-D seismic, while all of the Amoco
Properties have group 3-D seismic. A group 3-D seismic shooting was recently
completed on the western portion of the Company's properties in West Delta.

Marketing of Production

Production from the Company's properties is marketed in accordance with
industry practices, which include the sale of oil at the wellhead to third
parties and the sale of gas to third parties at prices based on factors normally
considered in the industry, such as the spot price for gas or the posted price
for oil, and the quality of the oil and gas.

The Company markets all of its offshore oil production to Amoco, Citgo,
Conoco, Texaco, Unocal and Vastar. Citgo, Conoco, Texaco and Vastar each have
25% calls (exclusive rights to purchase) on the oil production from the West
Delta Fields at their average posted price for each month. Amoco has a call on
all of the oil production from the Amoco Properties at their posted prices. If
the Company has a bona fide offer from a crude oil purchaser at a higher price
than Amoco's posted price, then Amoco must match that price or release the call.
Oil from the Zapata Properties is currently being sold to Unocal and Amoco, but
can be sold to any crude oil purchaser of the Company's choice. Natural gas is
sold on the spot market. There are numerous potential purchasers for offshore
gas. Notwithstanding this, natural gas purchased by Tenneco Gas Marketing
Company accounted for 49% of the revenues in 1996. There are numerous gas
purchasers doing business in the areas involved as well as natural gas brokers
and clearing houses. Furthermore, the Company can contract to sell the gas
directly to end users. The Company does not believe that it is dependent upon
any one customer or group

of customers for the purchase of natural gas.

The Company hedges the prices of its oil and gas production through the
use of oil and natural gas futures and swap contracts within the normal course
of its business. The Company uses futures and swap contracts to reduce the
effects of fluctuations in oil and natural gas prices. Changes in the market
value of these contracts are deferred and subsequent gains and losses are
recognized monthly as adjustments to revenues in the same production period as
the hedged item, based on the difference between the index price and the
contract price. The Company entered into a hedge agreement beginning in January,
1996, for the delivery of 15,000 MMBtu of gas for each day in 1996 with contract
prices ranging from $1.7511 per MMBtu to $2.253 per MMBtu.

Starting in 1997 the Company's hedge transactions on natural gas are based upon
published gas pipeline index prices and not the NYMEX. This change has
eliminated price differences due to transportation. For 1997, 14,000 MMBtu's per
day has been hedged, reduced to 10,000 MMBtu's per day in 1998 and 7,000 MMBtu's
per day in 1999. The Company is hedging at a swap price of $1.80 per MMBtu for
1997, with varying levels of participation (93% in January to 40% in September)
in settlement prices above $1.80 per MMBtu.

Starting in 1997, the Company has also hedged 720 barrels of oil for each day in
1997 at a swap price of $20.00 per barrel, with a 40% participation in
settlement prices above the swap price.

Plugging and Abandonment Escrows

Pursuant to existing agreements the Company is required to deposit funds
in bank trust and escrow accounts to provide a reserve against satisfaction of
its eventual responsibility to plug and abandon wells and remove structures when
certain fields no longer produce oil and gas. Each month, until November 1997,
$25,000 is deposited in a bank escrow account, to satisfy such obligations with
respect to a portion of its West Delta Properties. The Company has entered into
an escrow agreement with Amoco Production Company under which the Company will
deposit, for the life of the fields, in a bank escrow account ten percent (10%)
of the net cash flow, as defined in the agreement, from the Amoco properties. As
of December 31, 1996 the Company has established the "PANACO East Breaks 110
Platform Trust" in favor of the Minerals Management Service of the U.S.
Department of the Interior. This trust requires an initial funding of $846,720
in December 1996, and remaining deposits of $244,320 due at the end of each
quarter in 1999 and $144,000 due at the end of each quarter in 2000, for a total
of $2,400,000. In addition, the Company has $9,250,000 in surety bonds to secure
its plugging and abandonment obligations; including a $4,100,000 bond which was
provided to the original sellers of the West Delta Properties; a $2,400,000
supplemental bond provided to the Minerals Management Service of the U.S.
Department of the Interior in connection with the plugging and structure removal
obligations for the Company's East Breaks Block 110 Platform and a $300,000
Pipeline Right-of-Way Bond.

Insurance

The Company maintains insurance coverage as is customary for companies of
a similar size engaged in operations similar to the Company's. The Company's
insurance coverage includes comprehensive general liability insurance in the
amount of $50,000,000 per occurrence for personal injury and property damage and
cost of control and operators extra expense insurance of $3,000,000 on onshore
wells, $20,000,000 on wells in Louisiana State waters and $50,000,000 per
occurrence in Federal offshore waters, which limits are proportionately reduced
when the Company owns less than 100% of the respective property. The Company
maintains $65,000,000 in property insurance on its offshore properties. There is
no assurance that such insurance

will be adequate to cover all such costs or that such insurance will continue to
be available in the future or that such insurance will be available at premium
levels that justify its purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on the
Company's financial condition and operations.

Funding of Business Activities

Cash Flow from Operations. Funding for the Company's activities is
provided primarily by cash flow from operations, however, the Company may use
its Bank Facility and other sources described below. Generally, cash flow from
properties declines over time as production declines. The cash flow generated by
the Company's activities would decline in the absence of (a) the acquisition and
development of other oil and gas properties, (b) increases in the Company's
production of oil and gas resulting from the development of its properties, or
(c) increases in the prices that the Company receives for oil and gas
production.

Issuance of Additional Common Shares and Other Securities. The Company may
issue additional Common Shares or other securities for cash, to the extent that
market and other conditions permit, and use the proceeds to fund its activities.
Additional securities issued by the Company may be of a class preferred as to
the Common Shares with respect to such matters as dividends and liquidation
rights and may also have other rights and preferences as determined by the Board
of Directors. The Certificate of Incorporation and By-laws of the Company
generally do not require the Company to obtain the consent of its shareholders
for the issuance and sale of Common Shares or other securities.

Borrowings and Obligations. The Company is permitted to incur indebtedness
for any Company purpose. It is currently expected that Company indebtedness will
consist primarily of borrowings from commercial banks and credit corporations,
the sale of debt instruments, and possibly by advances from oil and gas
purchasers.

On October 8, 1996, the Company amended its bank facility with First Union
National Bank of North Carolina (60% participation), and Banque Paribas (40%
participation), herein "Bank Facility". The loan is a reducing revolver designed
to provide the Company up to $40,000,000 depending on the Company's borrowing
base, as determined by the lenders. The Company's borrowing base at December 31,
1996 was $31 million, with an availability under the revolver of $2,500,000. The
principal amount of the loan is due July 1, 1999. However, at no time may the
Company have outstanding borrowings under the Bank Facility in excess of its
borrowing base. Interest on the loan is computed at the bank's prime rate or at
1 to 1 3/4% (depending upon the percentage of the facility being used) over the
applicable London Interbank Offered Rate ("LIBOR") on Eurodollar loans.
Eurodollar loans can be for terms of one, two, three or six months and interest
on such loans is due at the expiration of the terms of such loans, but no less
frequently than every three months. Management feels that this bank facility
greatly enhances its ability to make necessary capital expenditures to maintain
and improve production from its properties and makes available to the Company
additional funds for future acquisitions. The bank facility is collateralized by
a first mortgage on the Company's offshore properties. The loan agreement
contains certain covenants including a requirement to maintain a positive
indebtedness to cash flow ratio, a positive working capital ratio, a certain
tangible net worth, as well as limitations on future debt, guarantees, liens,
dividends, mergers, material change in ownership by management, and sale of
assets.

In 1991, the Company borrowed $21,600,000 from New England Mutual Life
Insurance Company, NMB Post Bank, Groep, N.V. (now ING Bank), the Lincoln
National Life Insurance Company and En Cap 1989-1 Limited Partnership. The
balance owed on this facility was prepaid in 1994 with part of the proceeds of
the Company's Bank Facility. As part of the 1991 transaction these former
lenders received a net profits interest in part of the West Delta Properties.

From time to time the Company has borrowed funds from institutional
lenders who are advised by Kayne, Anderson Investment Management, Inc. In each
case these loans are due at a stated maturity, require payments of interest only
at 12% per annum 45 days after the end of each calendar quarter and are secured
by a second mortgage on the Company's offshore oil and gas properties. The
respective loan documents contain certain covenants including a requirement to
maintain a net worth ratio, as well as limitations on future debt, guarantees,
liens, dividends, mergers, material change in ownership by management, and sale
of assets. The loans are as follows:

(a) 1993 Subordinated Notes. In 1993, $5,000,000 was borrowed, due
December 31, 1999. These notes were prepaid on March 6, 1997, with part of
the proceeds of the recent Common Share offering. The lenders were issued,
and during 1996 exercised, warrants to acquire 816,526 Common Shares at
$2.25 per share.

(b) 1996 Tranche A Convertible Subordinated Notes. On October 8,
1996, $8,500,000 was borrowed, due October 8, 2003, but prepayable any
time after May 8, 1998. After August 28, 1997 the Notes are convertible
into 2,060,606 Common Shares on the basis of $4.125 per share. The Company
may deliver up to $2,000,000 in PIK notes in satisfaction of interest
payment obligations.

(c) 1996 Tranche B Bridge Loan Subordinated Notes. On October 8,
1996, $8,500,000 was borrowed, due October 8, 2003. These Notes were
prepaid on March 6, 1997, with part of the proceeds of the recent Common
Share Offering.

Competition, Markets, Seasonality and Regulation

Competition. There are a large number of companies and individuals engaged
in the exploration for and development of oil and gas properties. Competition is
particularly intense with respect to the acquisition of oil and gas producing
properties. The Company encounters competition from various independent oil
companies in raising capital and in acquiring producing properties. Many of the
Company's competitors have financial resources and staffs considerably larger
than the Company.

Markets. The ability of the Company to produce and market oil and gas
profitably depends on numerous factors beyond the control of the Company. The
effect of these factors cannot be accurately predicted or anticipated. These
factors include the availability of other domestic and foreign production, the
marketing of competitive fuels, the proximity and capacity of pipelines,
fluctuations in supply and demand, the availability of a ready market, the
effect of federal and state regulation of production, refining, transportation,
and sales of oil and gas, political instability or armed conflict in
oil-producing regions, and general national and worldwide economic conditions.
In recent years, worldwide oil production capacity and gas production capacity
in the United States exceeded demand and resulted in a substantial decline in
the price of oil and natural gas in the United States.

Since early 1986, certain members of the Organization of Petroleum
Exporting Countries ("OPEC") have, at various times, dramatically increased
their production of oil, causing a significant decline in the price of oil in
the world market. The Company cannot predict future levels of production by the
OPEC nations, the prospects for war or peace in the Middle East, or the degree
to which oil and gas prices will be affected, and it is possible that prices for
any oil, natural gas liquids, or gas produced by the Company will be lower than
those currently available.

The demand for gas in the United States has fluctuated in recent years due
to economic factors, a

deliverability surplus, conservation and other factors. This lack of demand has
resulted in increased competitive pressure on producers. However, environmental
legislation is requiring certain markets to shift consumption from fuel oils to
natural gas, thereby increasing demand for this cleaner burning fuel.

In view of the many uncertainties affecting the supply and demand for oil,
gas, and refined petroleum products, the Company is unable to predict future oil
and gas prices. In order to minimize these uncertainties the Company, from time
to time, hedges prices on a portion of its production with futures contracts.

Seasonality. Historically the nature of the demand for natural gas caused
prices and demand to vary on a seasonal basis. Prices and production volumes
were generally higher during the first and fourth quarters of each calendar
year. For example, during 1991 the price the Company receives for its natural
gas fell from a high of $1.78 per Mcf in January to a low of $1.09 in July and
then climbed to a new high of $1.95 in December, averaging $1.49 for the year.
However, the substantial amount of gas storage becoming available in the U.S. is
altering this seasonality. During 1993, 1994 and 1995 the Company's gas prices
ranged from $2.78 to $1.64, $2.43 to $1.39 and $2.37 to $1.37, averaging $2.13,
$1.88 and $1.58, respectively, in each case, per Mcf. Gas prices averaged $2.17
per Mcf during 1996. The Company sells its natural gas on the spot market based
upon published index prices for each pipeline. Historically the net price
received by the Company for its gas has averaged about $.10 per MMBtu below the
NYMEX Henry Hub index price, due to transportation differentials. Fields that
are located further offshore, such as the Amoco Properties, will generally sell
their gas for as much as $.20 below that index price.

Regulation. The Company's business is affected by governmental laws and
regulations, including price control, energy, environmental, conservation, tax
and other laws and regulations relating to the petroleum industry. For example,
state and federal agencies have issued rules and regulations that require
permits for the drilling of wells, regulate the spacing of wells, prevent the
waste of natural gas and crude oil reserves, and regulate environmental and
safety matters including restrictions on the types, quantities and concentration
of various substances that can be released into the environment in connection
with drilling and production activities, limits or prohibitions on drilling
activities on certain lands lying within wetlands and other protected areas, and
remedial measures to prevent pollution from current and former operations.
Changes in any of these laws, rules and regulations could have a material
adverse effect on the Company's business. In view of the many uncertainties with
respect to current law and regulations, including their applicability to the
Company, the Company cannot predict the overall effect of such laws and
regulations on future operations.

The Company believes that its operations comply in all material respects
with all applicable laws and regulations and that the existence of such laws and
regulations have no more restrictive effect on the Company's method of
operations than on other similar companies in the industry. The following
discussion contains summaries of certain laws and regulations and is qualified
in its entirety by reference thereto.

Various aspects of the Company's oil and natural gas operations are
regulated by administrative agencies under statutory provisions of the states
where such operations are conducted and by certain agencies of the federal
government for operations of federal leases. The Federal Energy Regulatory
Commission (the "FERC") regulates the transportation and sale for resale of
natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the
"NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the
federal government has regulated the prices at which oil and gas could be sold.
Currently, sales by producers of natural gas, and all sales of crude oil,
condensate and natural gas liquids can be made at uncontrolled market prices,
but Congress could reenact price controls at any time. Deregulation of wellhead
sales in the natural gas industry began with the enactment of the NGPA in 1978.
In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act which removed
all NGA and NGPA price and non-price controls affecting wellhead sales of
natural gas effective

January 1, 1993.

Sales of crude oil, condensate and gas liquids by the Company are not
regulated and are made at market prices. The price the Company receives from the
sale of these products is affected by the cost of transporting the products to
market. Effective as of January 1, 1995, the FERC implemented regulations
establishing an indexing system for transportation rates for oil pipelines,
which would generally index such rates to inflation, subject to certain
conditions and limitations. These regulations could increase the cost of
transporting crude oil, liquids and condensates by pipeline. These regulations
are subject to pending petitions for judicial review. The Company is not able to
predict with certainty what effect, if any, these regulations will have on it,
but other factors being equal, the regulations may tend to increase
transportation costs or reduce wellhead prices for such conditions.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC and the courts. The Company
cannot predict when or whether any such proposals may become effective. In the
past, the natural gas industry historically has been very heavily regulated.
There is no assurance that the current regulatory approach pursued by the FERC
will continue indefinitely into the future. Notwithstanding the foregoing, it is
not anticipated that compliance with existing federal, state and local laws,
rules and regulations will have a material or significantly adverse effect upon
the capital expenditures, earnings or competitive position of the Company.

Extensive federal, state and local laws and regulations govern oil and
natural gas operations regulating the discharge of materials into the
environment or otherwise relating to the protection of the environment. Numerous
governmental departments issue rules and regulations to implement and enforce
such laws which are often difficult and costly to comply with and which carry
substantial penalties for failure to comply. Some laws, rules and regulations
relating to protection of the environment may, in certain circumstances, impose
"strict liability" for environmental contamination, rendering a person liable
for environmental damages and response costs without regard to negligence or
fault on the part of such person. For example, the federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended, also
known as the "Superfund" law, imposes strict liability on an owner and operator
of a facility or site where a release of hazardous substances into the
environment has occurred and on companies that disposed or arranged for the
disposal of the hazardous substances released at the facility or site. The
regulatory burden on the oil and natural gas industry increases its cost of
doing business and consequently affects its profitability. These laws, rules and
regulations affect the operations and costs of the Company. While compliance
with environmental requirements generally could have a material adverse effect
upon the capital expenditures, earnings or competitive position of the Company,
the Company believes that other independent energy companies in the oil and gas
industry likely would be similarly affected. The Company believes that it is in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on the Company.

Offshore operations of the Company are conducted on both federal and
state lease blocks of the Gulf of Mexico. In all offshore areas the more
stringent regulation of the federal system, as implemented by the Mineral
Management Service of the Department of the Interior, are to be applicable to
state leases as well as federal leases. The Oil Pollution Act of 1990 requires
operators of oil and gas leases on or near navigable waterways to provide
$35,000,000 in "financial responsibility", as defined in the Act. At present the
Company is satisfying the financial responsibility requirement with insurance
coverage.

Employees

The Company has fourteen full time employees, some of whom are officers.
The Company utilizes an

additional thirty-two contract personnel in the operation of the offshore
properties, and uses numerous outside geologists, production engineers,
reservoir engineers, geophysicists and other professionals on a consulting
basis.

Office Facilities

The Company's headquarters are located at 1050 West Blue Ridge Boulevard,
PANACO Building, Kansas City, Missouri 64145-1216, and its telephone number is
(816) 942-6300, FAX (816) 942-6305. The Houston, Texas office is located at 1100
Louisiana, Suite 5110, Houston, Texas 77002-5220, telephone (713) 652-5110, FAX
(713) 651-0928.

Item 2. Properties.

The Company's offshore properties are located offshore Louisiana and
Texas. The following table sets forth certain information with respect to the
Company's significant properties as of December 31,1996. Such properties account
for 95% of the aggregate SEC 10 Value of its properties.

Significant Proved Properties

Proved Reserves
Oil Gas SEC 10
Property Area (Bbls) (Bcf) Value

AMOCO PROPERTIES Offshore TX 1,332,000 15.8 $ 42,690,000
WEST DELTA PROPERTIES Offshore LA 395,000 14.8 $ 41,586,000
ZAPATA PROPERTIES Offshore TX & LA 168,000 8.5 $ 22,966,000

Amoco Acquisition

On August 26, 1996 the Company entered into a Purchase and Sale
Agreement with Amoco Production Company to acquire Amoco's interest in 13
offshore blocks comprising six fields in the Gulf of Mexico ("Amoco
Properties"). The acquisition closed October 8, 1996. The purchase price for the
assets acquired in this transaction was $40,400,000, paid by the issuance of
2,000,000 Common Shares, at $4.20 per share, and by payment to Amoco of
$32,000,000 in cash.

In addition to the interests acquired, the Company purchased a 33.3%
interest in a 12.67 mile 12" pipeline connecting East Breaks Block 160 platform
to the High Island Offshore System ("HIOS"), a natural gas pipeline system in
the Gulf of Mexico and a 33.3% interest in a 17.47 mile 10" pipeline connecting
the East Breaks Block 160 platform to the High Island Pipeline System ("HIPS"),
a crude oil pipeline system in the Gulf of Mexico. HIOS and HIPS are the primary
natural gas and crude oil pipeline systems in that part of the Gulf of Mexico.

The East Breaks Block 160 platform also serves a subsea well owned by
Mobil Oil Corporation in East Breaks Block 117. Under agreements with Mobil the
owners of the East Breaks Block 160 platform share in certain fees paid by
Mobil.

The following table lists the field names, block numbers, working
interests, net revenue interests and number of wells of the properties.

Working Net Revenue Number of

Field/Block Interest Interest Active Wells

East Breaks 160 Field
EB 160 (OCS 2647) 0.3333 0.2778 13
EB 161 (OCS 2648) 0.3333 0.2778 10

High Island A-302 Field
HI A-302 (OCS 2732) 0.3333 0.2778 5

High Island A-309 Field
HI A-309 (OCS 2735) 0.5000 0.4167 9
HI A-310 (OCS 3378) 0.5000 0.4167 8

High Island A-330 Field
HI A-330 (OCS 2421) 0.1200 0.1000 25
HI A-349 (OCS 2743) 0.1200 0.1000 6
WC 613 (OCS 3286) 0.1200 0.1000 3

High Island A-474 Field
HI A-474 (OCS 2366) 0.1200 0.1000 18
HI A-489 (OCS 2372) 0.1200 0.1000 22
HI A-499 (OCS 3118) 0.1310 0.1092 6
HI A-475 (OCS 2367) 0.1200 0.1000 0

West Cameron 180 Field
WC 144 (OCS 1953) 0.1250 0.1042 7

Average net production from these fields during 1996 was 11.5 MMcf of gas
per day and 583 barrels of oil per day and cash flow net to the interests was
$11,200,000. Management believes that these fields have potential for
substantial reserve and production increases. Three of the fields have
proprietary 3-D seismic.

East Breaks 160 Field

This field consists of two blocks, East Breaks 160 and 161. The water
depth ranges from 900' to 1,100'. The Company owns a 33.3% working interest with
a 27.8% net revenue interest. Unocal Corporation is the operator. East Breaks
160 field produces from an anticlinal ridge with 12 productive horizons. A
proprietary 3-D survey was shot and processed in 1990. Net proved reserves are
estimated to be 9.7 Bcf and 1,131 MBO. The GA-2 and HB-2 reservoirs account for
most of the reserves. Additional income is derived from processing fees from the
Mobil Oil Corporation recent discovery in adjacent Block 117. This subsea well
is tied back to the East Breaks 160 platform. Management believes there are
numerous reservoirs in the field which have not been adequately evaluated with
wells. Additional wells on Blocks 160 and 161 and in adjacent blocks are under
consideration by Unocal Corporation.

High Island A-302 Field

High Island Block A-302 is in approximately 200' of water. The Company
owns a 33.3% working interest with a 27.8% net revenue interest. Unocal
Corporation is the operator. Production is from four producing

horizons on a faulted anticlinal structure. A speculative 3-D survey was shot in
1991 and processed in 1992. One well is producing, with one well scheduled to be
recompleted in 1997. Management believes additional reserves should be
recoverable from two sands in an area which seismic data shows to be undrained
by the existing wells.

High Island A-309 Field

High Island A-309 field consists of two blocks, High Island A-309 and
A-310, in approximately 200' of water. The Company owns a 45% working interest
in Block A-309 and a 55% working interest in Block A-310. Coastal Oil and Gas
Corporation is the operator. Production is from three faulted anticlines with 18
productive horizons. Proprietary 3-D seismic data has been reprocessed. Net
Proved Reserves are estimated to be 4.0 Bcf.
Numerous additional wells and recompletions are planned for 1997 through 1999.

High Island A-330 Field

The field consists of three blocks, High Island A-330, High Island A-349
and West Cameron 613. The field is located in 280' of water. The Company owns a
12% working interest with a 10% net revenue interest. Costal Oil and Gas
Corporation is the operator. Three wells have been recompleted in 1996. This
field produces from a faulted anticline with 24 productive horizons. The Company
has 2-D seismic on this field, but a 3-D seismic survey was recently shot.
Management believes that significant upside potential was delineated by the 3-D
seismic. A well in West Cameron Block 613 has been proposed by the operator for
1997 to offset a field operated by Shell offshore in Block A-350 and other wells
and recompletions are under consideration.

High Island A-474 Field

This field consists of three full blocks in the High Island Area, A-474,
A-489, A-499, and part of Block A- 475. The water depth is 250' to 285 and
Phillips Petroleum Company ("Phillips") is the operator. The Company owns a 12%
working interest with a 10% net revenue interest in Blocks A-474 and A-489, a
13.1% working interest with a 10.9% net revenue interest in Block A-499, and a
12% working interest with a 9% net revenue interest in Block A-475. There are 23
productive horizons in this faulted anticline. A proprietary 3-D seismic was
shot in 1991 and processed in 1993. Net Proved Reserves are 1.2 Bcf and 199 MBO.

West Cameron 180 Field

This field consists of a single block, West Cameron 144, in 40' of water.
Texaco is the operator. The Company owns a 12.5% working interest with a 10.4%
net revenue interest. The producing feature is a north- plunging faulted
anticline that underlies West Cameron Blocks 173 and 180. There are three
productive horizons.

West Delta Properties

These properties consist of 13,565 acres in Blocks 52 through 56 and
Block 58 in the West Delta Area, offshore Louisiana. The properties have 36
wells, five of which were recently drilled. The West Delta Properties were
acquired from Conoco, Inc., Atlantic Richfield Company (now Vastar Resources,
Inc.), OXY USA, Inc. and Texaco Exploration and Production, Inc. in May 1991.
During 1995 the properties had net production averaging approximately 20,643 Mcf
of natural gas per day and 264 barrels of oil and condensate per day. During
1996 production was substantially diminished by the explosion and fire.

The Company has a 87.5% net revenue interest in the field, subject to a 5%
net profits interest on the shallower reservoirs in favor of the Companys'
former lenders and a 4.166% overriding royalty interest on the deeper reservoirs
in favor of Conoco and OXY. In 1994 the Company spent $6,900,000 on drilling
four wells and the recompletion of eight wells on these properties. The Company
is the operator and generally owns 100% of the working interest in these wells.
Presently, the wells produce from depths ranging from 1,200 feet to 12,500 feet.
Because of the existing surface structures and production equipment, management
believes that additional wells can be added on the properties with lower
completion costs.

The Company has agreed to farmout the deep rights in West Delta Blocks 53
through 56 to Flores & Rucks, Inc., which has agreed to fund a new 3-D seismic
survey. The Company retains all presently producing reservoirs. Management
believes this farmout will bring about an evaluation of any deep reservoir
potential and allow the Company to further evaluate the presently producing
reservoirs using the new 3-D seismic. The Company will have the option of
retaining a 12 1/2% overriding royalty interest or participating up to 50% as a
working interest owner in any wells drilled by Flores & Rucks, Inc.

During 1994 the Company farmed out the deep rights (below 11,300 feet)
to an 1,875 acre parcel in Block 58 to Energy Development Corporation which
drilled a successful well to 16,500 feet. Production commenced in April, 1995.
The Company retained a 12 1/2% overriding royalty interest in that acreage that
converts to a 15% overriding royalty interest at Payout. The well has produced
as much as 21,000 Mcf per day and 1,500 barrels of condensate per day. Energy
Development Corporation was subsequently acquired by Samedan Oil Corporation.

The main production facility on the West Delta Properties is a four
platform complex designated as Tank Battery #3. There are four ancillary
platforms in the eastern portion of the properties connected to Tank Battery #3.
Three wells are on one of these platforms. In the western portion there is one
production platform designated as Platform "D" in Block 58, with three wells.
The remaining 30 wells are located on satellite structures connected to Tank
Battery #3 or one of its ancillary platforms. Eight wells produce oil and
natural gas. The remaining wells produce only natural gas.

The Company has recently replaced the pipeline connecting "D" Platform in
Block 58 with Tank Battery # 3 in Block 54 with two new 6" pipelines.

In connection with the acquisition of the West Delta offshore
properties the Company provides the sellers with a $4,100,000 plugging and
abandonment bond collateralized in part with a bank escrow account.

Zapata Properties

On July 12th, 1995, the Company entered into a Purchase and Sale
Agreement with Zapata Exploration Company ("Zapata") to acquire all of Zapata's
offshore oil and gas properties in the Gulf of Mexico. The properties consist of
East Breaks Blocks 109 and 110, East Cameron Block 359, Eugene Island Block 372,
South Timbalier Block 185 and West Cameron Block 538, totaling 31,134 gross
acres. The transaction was closed July 26, 1995. The Company took over as
operator of the East Breaks and West Cameron properties effective at closing.
The East Cameron property is operated by Anadarko Petroleum Corporation. The
Eugene Island

property is operated by Unocal Corporation and the South Timbalier property is
operated by Louisiana Land & Exploration Company. Proved net reserves at
December 31, 1996 were 168,000 Bbls of oil and 8.5 Bcf of natural gas. During
1996, the properties produced 49,275 barrels of oil and 3.5 Bcf of natural gas,
net to the Company's interest.

In addition to the mineral interests acquired, the Company purchased a
100% interest in a 31 mile natural gas pipeline connecting the Company's East
Breaks 110 platform to the High Island Offshore System and a 22 mile oil
pipeline which connects the East Breaks 110 platform with the High Island
Pipeline System. HIOS and HIPS are the primary natural gas and crude oil systems
in that part of the Gulf of Mexico.

The Company's East Breaks 110 platform has significant excess capacity
for both crude oil and natural gas. Prior to the acquisition of the properties,
Zapata had entered into a Facilities Sharing Agreement with AGIP Petroleum
Company, Inc. ("AGIP") to operate and process for AGIP's subsea wells in Blocks
112 and 157. Under the Agreement AGIP will pay certain fees to the Company and
split the cost of operating the East Breaks 110 platform with the Company, based
upon each company's proportion of production. A portion, not to exceed
$6,000,000, of the monies earned pursuant to this Agreement are being paid to
Zapata as part of the acquisition of the properties.

The purchase price for the assets acquired in the transaction was
$2,748,000 in cash and the obligation to pay a production payment to Zapata
based upon future production. The production payment is based upon production
from the East Breaks 109 Field after production of 12 Bcfe gross (10 Bcfe net)
measured from October 1, 1994. The Company will pay to Zapata $.4167 per Mcfe on
the next 27 Bcfe of gross production, if that much is produced. Payments to
Zapata on this production payment are to be made by the Company when it is paid
for the oil or gas. The Company's oil and gas reserves are calculated net of
this production payment.

Bayou Sorrel Field

As of December 27, 1995 the Company acquired from Shell Western E &
P, Inc. all of its interest in the Bayou Sorrel Field in Iberville Parish,
Louisiana. The purchase price of the field and a related receivable of $600,000
was $10,455,000 in cash, including a $205,000 brokers' fee.

Effective September 1, 1996 the Company sold the Bayou Sorrel Field to
National Energy Group, Inc. for $11,000,000. The Company received $9,000,000 in
cash and 477,612 shares of National Energy Group, Inc. common stock, which were
valued at $2,000,000 as of the November 26, 1996, the closing date. These shares
are restricted securities and are not freely tradeable. The Company has demand
registration rights and has made such a demand. The Company retained a 3%
overriding royalty interest in the deep rights of the field at depths below
11,000 feet.

Oil and Gas Information

The following tables set forth selected oil and gas information for the
Company, and certain forward looking information about its properties. Future
results may vary significantly from the amounts reflected in the information set
forth herein because of normal production declines and future acquisitions.

Proved Reserves (a) (b)

The following table sets forth information as of December 31, 1996 as
to the estimated Proved Reserves attributable to the Company's properties.

Oil and liquids (Bbls):
Proved Developed Reserves .........................1,867,000
Proved Undeveloped Reserves ....................... 372,000
Total Proved Reserves .........................2,239,000

Natural gas (Mcf):
Proved Developed Reserves ........................39,288,000
Proved Undeveloped Reserves ...................... 2,158,000
Total Proved Reserves ........................41,446,000

(a) Calculated by the Company in accordance with the rules and regulations of
the SEC, based upon December 31, 1996 prices of $24.25 per barrel of oil
and $3.84 per MMBtu of gas, adjusted for basis differentials, Btu content
of gas and specific gravity of oil. The Company's independent reservoir
engineers prepare reserve reports as of the end of each calendar year.
(b) Includes the recently acquired Amoco Properties and excludes the recently
sold Bayou Sorrel Field.

Estimated Future Net Revenues
from Proved Reserves (a) (b)

The following table sets forth information as of December 31, 1996 as
to the estimated future net revenues (before deduction of income taxes) from the
production and sale of the Proved Reserves attributable to the Company's
properties.

Proved Total
Developed Proved
Reserves Reserves
Estimated Future net revenues (c):
1997..................... $ 42,223,000 $ 42,170,000
1998..................... 31,020,000 32,017,000
1999..................... 19,236,000 19,783,000
2000..................... 12,286,000 15,560,000
Thereafter............... 34,351,000 39,525,000
------------ ------------
Total.................... $ 139,115,000 $ 149,056,000
Present value (10%) of estimated future net
revenues (SEC 10 Value)... $ 106,918,000 $ 113,467,000

(a) Calculated by the Company in accordance with the rules and regulations
of the SEC, based upon December 31, 1996 prices of $24.25 per barrel of oil and
$3.84 per MMBtu of offshore gas, adjusted for basis differentials, Btu content
of gas and specific gravity of oil. The Company's independent reservoir
engineers prepare reserve reports as of the end of each calendar year.
(b) Includes the recently acquired Amoco Properties and excludes the
recently sold Bayou Sorrel Field.
(c) Estimated future net revenues represent estimated future gross revenues
from the production and sale of Proved Reserves, net of estimated operating
costs, future development costs estimated to be required to achieve estimated
future production and estimated future costs of plugging offshore wells and
removing offshore structures.

Production, Price, and Cost Data

The following table sets forth certain production, price, and cost
data with respect to the Company's properties, for the three years ended
December 31, 1996, 1995 and 1994.

For the years
ended December 31,

1996 1995 1994
---- ---- ----
Oil:
Net Production (Bbls)(a) 276,000 170,000 137,000
Revenue................... $ 5,356,000 $2,853,000 2,103,000
Average net Bbls per day 756 466 375
Average price per Bbl $ 19.42 $ 16.78 $ 15.35

Gas:
Net Production(Mcf)(a) 6,788,000 9,850,000 8,139,000
Revenue................... $ 14,707,000 $15,594,000 $15,235,000
Average net Mcf per day 19,000 27,000 22,300
Average price per Mcf $ 2.17 $ 1.58 $ 1.87

Total Revenues................. $ 20,063,000 $18,447,000 $17,338,000

Production Costs:
Production cost $ 8,477,000 $ 8,055,000 $ 5,231,000
Mcfe(b) 8,444,000 10,870,000 8,961,500
Production costs per Mcfe(c) $ 1.00 $ .74 $ .58
- ------
(a) Production information is net of all royalty interests, overriding
royalty interest and the net profits interest in the West Delta Properties owned
by the Company's former lenders.
(b) Oil production is converted to Mcfe (Equivalent Mcf) at the rate of 6
Mcf per Bbl, representing the estimated relative energy content of natural gas
to oil.
(c) The information shown for 1996 was impacted by the explosion and fire
on April 24th at West Delta Tank Battery #3, which resulted in those fields
being off production until October 7, 1996, when production resumed. For that
reason management would not consider these production costs to be indicative of
the future. Also this information includes Bayou Sorrel Field through August 31,
the date of its sale, and includes any information with respect to the Amoco
Properties after October 8, 1996.
Productive Wells(a)

The following table sets forth the number of productive oil and gas
wells, as of the date hereof, attributable to the Company's properties.

Gross productive offshore wells (b): Productive Wells Company Operated

Oil . . . . . . . . . . . . .33 . . . . .. . . . 10

Gas . . . . . . . . . . . . . .90 . . . . . . . . .42
Total . . . . . . . . .. .. .123 . . . . . . . . .52

Net productive offshore wells (c):
Oil . . . . . . . . . . . . . 15 . . . . . . . . .10
Gas . . . . . . . . . . . . . . .49 . . . . . . . . .38
Total . . . . . . . . . . . . 64 . . . . . . . . .48
- -----
(a) Productive wells consist of producing wells and wells capable of
production, including shut-in wells and water disposal and injection
wells. One or more completions in the same borehole are counted as one
well.
(b) A "gross well" is a well in which a working interest is owned. The
number of gross wells represents the sum of the wells in which a
working interest is owned.
(c) A "net well" is deemed to exist when the sum of the fractional working
interests in gross wells equals one. The number of net wells is the sum
of the fractional working interests in gross wells.

Leasehold Acreage

The following table sets forth the developed acreage as of the date
hereof attributable to the Company's properties, excluding onshore acreage which
is no longer significant.

Developed offshore acreage (a):
Gross acres (b)............................................. 103,771
Net acres (c).............................................. 43,645

(a) Developed acreage is acreage assignable to productive wells.
(b) A "gross acre" is an acre in which a working interest is owned. The
number of gross acres represents the sum of the acres in which a
working interest is owned.
(c) A "net acre" is deemed to exist when the sum of the fractional working
interests in gross acres equals one. The number of net acres is the sum
of the fractional working interests in gross acres.

Drilling Activities

The following table sets forth the number of gross productive and dry
wells in which the Company had an interest, that were drilled and completed
during the four years ended December 31, 1996. Such information should not be
considered indicative of future performance, nor should it be assumed that there
is necessarily any correlation between the number of productive wells drilled
and the oil and gas reserves generated thereby or the costs to the Company of
productive wells compared to the costs to the Company of dry wells.

Developmental Wells Exploratory Wells
Completed Dry Completed Dry
Oil Gas Oil Gas Oil Gas Oil Gas
--- --- --- --- --- --- --- ---
1993 3 0 0 0 0 0 0 0
1994 5 4 0 0 0 1 0 0
1995 0 0 0 0 0 0 0 3
1996 0 0 2 0 0 0 0 0
---- ---- ---- --- ---- ---- ---- ----

Total 8 4 2 0 0 1 0 3

Title to Oil and Gas Properties

In the case of acquired properties title opinions are obtained for the
more significant properties. Prior to the commencement of drilling operations a
thorough drillsite title examination is conducted and curative work performed
with respect to significant defects.

Undeveloped Acreage and Unproved Properties

The Company does not hold interest in a significant amount of
Undeveloped Acreage to which no Proved Reserves have been assigned. However, the
Company retained a 3% overriding royalty interest in depths below 11,000 feet
when it sold the Bayou Sorrel Field, and no reserves have been attributed to
these depths.

Forward-looking Statements

Forward-looking statements in this Form 10-K/A, future filings by the
Company with the Securities and Exchange Commission, the Company's press
releases and oral statements by authorized officers of the Company are intended
to be subject to the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995. Investors are cautioned that all forward-looking statements
involve risks and uncertainty, including without limitation, the risk of a
significant natural disaster, the inability of the Company to insure against
certain risks, the adequacy of its loss reserves, fluctuations in commodity
prices, the inherent limitations in the ability to estimate oil and gas
reserves, changing government regulations, as well as general market conditions,
competition and pricing. The Company believes that forward-looking statements
made by it are based on reasonable expectations. However, no assurances can be
given that actual results will not differ materially from those contained in
such forward-looking statements. The words "estimate", "anticipate", "expect",
"predict", "believe" and similar expressions are intended to identify
forward-looking statements.

PRO FORMA FINANCIAL INFORMATION

On October 8,1996, the Company closed its acquisition of interests in
thirteen offshore blocks comprising six fields in the Gulf of Mexico from Amoco
Production Company. The purchase price for the assets acquired in this
transaction was $40,400,000, paid by the issuance of 2,000,000 Common Shares and
by payment to Amoco of $32,000,000 in cash. Concurrently with this transaction
the Company entered into a new Bank Facility with First Union National Bank of
North Carolina and Banque Paribas under which its reducing revolving loan was
increased to $40,000,000, with an initial borrowing base (credit limit) of
$35,000,000. In addition to that facility, the Company borrowed $17,000,000
pursuant to the 1996 Tranche A Convertible Subordinated Notes and the 1996
Tranche B Bridge Loan Subordinated Notes.

On July 26, 1995, the Company completed the acquisition of all of the
offshore oil and gas properties in the Gulf of Mexico owned by Zapata
Exploration Company, the "Zapata Properties." The purchase price for the Zapata
properties and a related receivable of $174,000 ($84,000 at December 31, 1995)
was $2,748,000 in cash and an obligation to pay a production payment to Zapata
based on future production. See "Properties - Zapata Properties."

Effective September 1, 1996, the Company sold the Bayou Sorrel Field to
National Energy Group, Inc. for a sales price of $11,000,000, consisting of
$9,000,000 in cash and 477,612 shares of National Energy Group, Inc. common
stock, which were valued at $2,000,000 as of the closing date. The field was
purchased by the Company on December 27, 1995 from Shell Western E & P, Inc. for
$10,500,000, which included a $204,000 broker's fee and a related receivable of
$600,000.

PANACO, INC.
Unaudited Pro Forma Combined Statement of Income (Operations)
For the Year Ended December 31, 1996
(Amounts in thousands except per share data)

Amoco Bayou
Properties PANACO, Inc. Sorrel PANACO,
Inc.
Amoco Pro Forma Pro Forma Pro Forma Pro Forma
PANACO, Inc. Properties Adjustments Combined Adjustments Combined
-------------------------------------------------- -----------------------

REVENUS

Oil and gas revenue $ 20,063 $10,925 $ - $ 30,988 $ (2,010) $ 28,978

COSTS AND EXPENSES
Lease operating
8,477 2,538 110 11,125 (733) 10,392
Depreciation, depletion and amortization
9,022 - 6,974 15,996 (888) 15,108
Exploration expenses
- - - - - -
Provision for losses and (gains) on
disposition and write-down of assets
- - - - - -
General and administrative
772 - - 772 - 772
Production and ad valorem taxes
559 - - 559 (239) 320
West Delta fire loss
500 - - 500 - 500
------------ --------- ---------- ------------- ---------- -----------
Total
19,330 2,538 7,084 28,952 (1,860) 27,092
------------ --------- ---------- ------------- ---------- -----------

NET OPERATING INCOME (LOSS)
733 8,387 (7,084) 2,036 (150) 1,886
------------ --------- ---------- ------------- ---------- -----------

OTHER INCOME (EXPENSE)

Gain/(loss) on investment in securities (258) - - (258) - (258)

Interest income/(expense), (net) (2,514) - (1,630) (4,144) 588 (3,556)
------------ --------- ---------- ------------- ---------- -----------

Total (2,772) - (1,630) (4,402) 588 (3,814)

NET INCOME (LOSS) BEFORE INCOME TAXES
(2,039) 8,387 (8,714) (2,366) 438 (1,928)

INCOME TAXES (BENEFIT)
- - - - -
-
------------ --------- ---------- ------------- ---------- -----------

NET INCOME (LOSS)
$ (2,039) $ 8,387 $ (8,714) $ (2,366) $ 438 $(1,928)
============ ========= ========== ============= ========== ===========

PRIMARY EARNINGS (LOSS) PER SHARE $(0.16) $ (0.17) $ (0.13)
============ ============= ===========

Weighted average shares outstanding 12,742 1,540 14,282 14,282
============ ============= ===========

The accompanying notes are an integral
part of this statement.

PANACO, Inc.
Unaudited Pro Forma Combined Statement of Income (Operations)
For the Year Ended December 31, 1995
(Amounts in thousands except per share data)

PANACO, Inc.
Zapata Amoco Pro Forma Pro Forma
PANACO, Inc. Properties Properties Adjustments Combined
-----------------------------------------------------------------------------

REVENUES

Oil and gas revenue $ 18,447 $ 3,623 $ 12,528 $ - 34,598

COSTS AND EXPENSES
Lease operating
8,055 1,460 2,991 314 12,820
Depreciation, depletion and amortization
8,064 - - 12,408 20,472
Exploration expenses
8,112 - - - 8,112
Provision for losses and (gains) on
disposition and write-down of assets
751 - - - 751
General and administrative
690 - - - 690
Production and ad valorem taxes
1,078 - - - 1,078
-----------------------------------------------------------------------------
Total
26,750 1,460 2,991 12,722 43,923
-----------------------------------------------------------------------------

NET OPERATING INCOME (LOSS)
(8,303) 2,163 9,537 (12,722) (9,325)
-----------------------------------------------------------------------------

OTHER INCOME (EXPENSE)
Interest expense (net)
(987) - - (2,901) (3,888)
-----------------------------------------------------------------------------

NET INCOME (LOSS) BEFORE INCOME TAXES
(9,290) 2,163 9,537 (15,623) (13,213)

INCOME TAXES (BENEFIT)
- - - - -
-----------------------------------------------------------------------------

NET INCOME (LOSS) $ (9,290) $ 2,163 $ 9,537 $ (15,623) $ (13,213)
=============================================================================

PRIMARY EARNINGS (LOSS) PER SHARE $(0.81) $ (0.98)
=============== =================

Weighted average shares outstanding
11,505 2,000 13,505
=============== =================

The accompanying notes are an integral
part of this statement.

NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME (OPERATIONS)
For the years ended December 31, 1996 and 1995

1. Basis of Presentation

1996:

The Unaudited Pro Forma Statement of Income (Operations) for the year
ended December 31, 1996 presents the combined effects of the acquisition of the
Amoco Properties, which closed on October 8, 1996 and the sale of the Bayou
Sorrel Field, effective September 1, 1996 as if these transactions had been
consummated on January 1, 1995. The results of the Amoco Properties are included
in the Company's 1996 results of operations after the acquisition date, October
8, 1996. The pro forma revenues, expenses and adjustments for the Amoco
Properties are only for the period of January 1 to October 7, 1996.

Included in 1996 is the issuance of 2,000,000 Common Shares to Amoco
Production Company. These shares are included in the Company's 1996 actual
weighted average shares from October 8 to December 31, the 1,540,000 is the
weighted average number of shares from January 1 to October 7.

The 1996 pro forma total weighted average shares outstanding of
14,282,000 is based on the actual weighted average number of 12,742,000 and the
2,000,000 Common Shares issued to Amoco Production Company weighted for the
period of January 1 to October 7, or 1,540,000.

1995:

The Unaudited Pro Forma Statements of Income (Operations) for the year
ended December 31, 1995 presents the combined effects of the acquisition of the
Amoco Properties, which closed on October 8, 1996, and the Zapata Properties,
closed on July 26, 1995, as if the acquisitions had been consummated on January
1, 1995.

Because the Bayou Sorrel Field was purchased on December 27, 1995,
there was no activity included in the Company's results of operations in 1995,
and therefore, no pro forma elimination adjustments are necessary for 1995.

The results of the Zapata Properties are included in the Company's 1995
results of operations after the acquisition date, July 26, 1995. The pro forma
revenues, expenses and adjustments for the Zapata Properties are only for the
period of January 1 to July 25, 1995.

The 1995 pro forma total weighted average shares outstanding of
13,505,000 is based on the actual weighted average number of 11,505,000 and the
2,000,000 Common Shares issued to Amoco Production Company, weighted for the
entire year.

1996 & 1995:

There are no pro forma adjustments for General and Administrative
expenses as the Company anticipates no increases in this category based on the
nature of the assets acquired.

The shares issuable upon conversion of the 1996 Tranche A Convertible
Subordinated Notes, a part of the financing of the Amoco acquisition, are not
considered common stock equivalents and are not included

in the weighted average shares outstanding calculation for either period.

2. Amoco and Zapata Properties Pro Forma Adjustments

Additional lease operating expenses of $110,000 in 1996 and $314,000 in
1995 represent the estimated additional insurance costs of owning the Amoco
Properties and the Zapata Properties. These amounts are estimated using the
Company's current insurance rates for owning the properties acquired or similar
properties.

Additional depletion and depreciation expense of $6,974,000 in 1996 and
$12,408,000 in 1995 represents the estimated depletion and depreciation for
assets acquired in the respective acquisitions assuming the purchase prices and
proved reserve amounts were identical to those that existed at the time of the
actual acquisitions.

Additional interest expense of $1,630,000 in 1996 and $2,901,000 in
1995 represents the increased borrowings at January 1, 1995. The purchase price
assumed for each acquisition is the same as at the actual date of acquisition.
It is assumed that cash on hand at the beginning of 1995 was used for the
acquisitions, with the balance of any cash required being funded with the
Company's Bank Facility and the 1996 Subordinated Notes, using the rates in
effect at the time of the acquisition for the Bank Facility and 12% for the 1996
Subordinated Notes, also the same rate received at the time of the acquisition.
These assumptions would have required the Company to borrow $32,000,000 for the
cash portion of the Amoco Acquisition, $17,000,000 under the 1996 Subordinated
Notes at 12% and $15,000,000 under the Company's Bank Facility, with an assumed
interest rate of 7.25%, the actual weighted average rate the Company incurred at
the time of the acquisition.

3. Bayou Sorrel Pro Forma Adjustments

The adjustments with respect to the sale of the Bayou Sorrel Field
represent the revenues and expenses of the Field from January 1 to August 31,
1996. Interest expense is reduced to reflect the elimination of the financing
for the acquisition, closed on December 28, 1995. The reduction in interest
expense is based on the Company's pro forma elimination of the debt associated
with the purchase of the Bayou Sorrel Field. The Company borrowed $10,455,000
for the purchase which closed on December 28, 1995, and had reduced this amount
during 1996. The interest rate averaged approximately 7.5%. The purchase price
for the Field was $10,455,000 which included a related receivable of $600,000
and a brokers fee of $205,000.

Although the sale of the Bayou Sorrel field closed on November 22,
1996, the buyer assumed all benefits and liabilities of the assets sold after
the effective date of the sale, September 1, 1996.

Item 3. Legal Proceedings.

The Company is presently a party to several legal proceedings, which it
considers to be routine and in the ordinary course of its business. Management
has no knowledge of any pending or threatened claims that could give rise to any
litigation which management believes would be material to the Company.

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

None.

Item 5. Description of Capital Stock.

The authorized capital shares of the Company consist of 40,000,000
Common Shares, par value $.01 per share, and 5,000,000 preferred shares, par
value $.01 per share. The following description of the capital shares of the
Company does not purport to be complete or to give full effect to the provisions
of statutory or common law and is subject in all respects to the applicable
provisions of the Company's Certificate of Incorporation and the information
herein is qualified in its entirety by this reference.

Common Shares

The Company is authorized by its Certificate of Incorporation, as
amended, to issue 40,000,000 Common Shares, of which 20,382,087 shares are
issued and outstanding as of the date hereof and are held by over 6,000
shareholders.

The holders of Common Shares are entitled to one vote for each share
held on all matters submitted to a vote of common holders. The Common Shares
have no cumulative voting rights, which means that the holders of a majority of
the Common Shares outstanding can elect all the directors if they choose to do
so. In that event, the holders of the remaining shares will not be able to elect
any directors.

Each Common Share is entitled to participate equally in dividends, as
and when declared by the Board of Directors, and in the distribution of assets
in the event of liquidation, subject in all cases to any prior rights of
outstanding preferred shares. The Common Shares have no preemptive or conversion
rights, redemption rights, or sinking fund provisions. The outstanding Common
Shares are duly authorized, validly issued, fully paid, and nonassessable.

Warrants

The Company has outstanding warrants to acquire 289,365 Common Shares
at prices ranging from $2.00 to $2.375. These warrants contain limited
provisions for adjustment of the number of shares in the event of a subdivision,
combination or reclassification of Common Shares. They do not have any rights to
demand registration or "piggy back" rights in the event of a registration of
Common Shares.

A group of the Company's lenders, pursuant to the 1993 Subordinated
Notes, acquired 443,221 Common Shares upon the exercise of warrants, which are
restricted securities within the meaning of the Securities Act of 1933 and can
only be sold pursuant to an exemption from registration or an offering which is
the subject of an effective registration statement. The holders of these shares
have demand registration rights and "piggy back" rights in the event the Company
registers an offering of its Common Shares.

Convertible Securities

After August 28, 1997, a group of the Company's lenders, pursuant to
the 1996 Tranche A Convertible Subordinated Notes issued October 8, 1996, have
the right to convert $8,500,000 in notes into 2,060,606 Common Shares at $4.125
per share, which Common Shares would be restricted securities within the meaning
of the Securities Act of 1933 and can only be sold pursuant to an exemption from
registration or an offering which is the subject of an effective registration
statement. The holders of these shares, after conversion, will have the right to
demand registration of the shares or "piggy back" in the event the Company
registers an offering of its Common Shares.

Preferred Shares

Pursuant to the Company's Certificate of Incorporation, the Company is
authorized to issue 5,000,000 preferred shares, and the Company's Board of
Directors, by resolution, may establish one or more classes or series of
preferred shares having the number of shares, designations, relative voting
rights, dividend rates, liquidation and other rights preferences, and
limitations that the Board of Directors fixes without any shareholder approval.

A number of preferred shares equal to one share for every one hundredth
of one Common Share outstanding has been reserved for issuance pursuant to the
Company's Shareholder Rights Plan, and designated as Series A Preferred Shares.
No shares of this Series A Preferred Shares have been issued or are outstanding.
Other than the designation as Series A, the Series A Preferred Shares have not
had designations, preferences and rights established by the Board of Directors.
See "Shareholder Rights Plan," below. The designations, preferences and rights
will be established if and when any of the Series A Preferred Shares are to be
issued.

Transfer Agent

The transfer agent, registrar and dividend disbursing agent for the
Common Shares is American Stock Transfer and Trust Company, 6201 15th Avenue,
Brooklyn, New York 11204.

Price Range of Common Shares

The Common Shares are quoted on the National Association of Securities
Dealers, Inc. Automated Quotation System ("NASDAQ") - National Market, under the
symbol "PANA". They commenced trading September 21, 1989. The following table
sets forth, for the periods indicated, the high and low closing bid for the
Common Shares.

1994

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
High 3 5/8 4 3/8 4 5/8 4 1/4
Low 2 9/16 2 15/16 3 1/2 3 5/8
1995

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
High 4 5/16 4 7/8 5 5/16 5
Low 3 5/8 4 4 1/8 4
1996

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
High 5 4 1/2 6 6 3/8
Low 3 7/16 3 11/16 3 3/8 4 3/8

On March 18, 1997, the last sale price of the Common Shares as reported
on the NASDAQ- NM was $4.625 per share. There are approximately 6,000
shareholders of the Common Shares.

Dividend Policy

The Company has not paid any cash dividends on the Common Shares. The
Delaware General Corporation Law, to which the Company is subject, permits the
Company to pay dividends only out of its capital surplus (the excess of net
assets over the aggregate par value of all outstanding capital shares) or out of
net profits for the fiscal year in which the dividend is declared or the
preceding fiscal year. The Bank Facility and the Subordinated Notes require the
consent of the lenders to any dividends or distributions by the Company and to
any purchases by the Company of Common Shares. The Company retains its earnings
and cash flow to finance the expansion and development of its business and
currently does not intend to pay dividends on the Common Shares. Any future
payments of dividends will depend on, among other factors, the earnings, cash
flow, financial condition, and capital requirements of the Company.

Shareholder Rights Plan

On August 2, 1995, the Board of Directors declared a dividend
distribution of one Right for each outstanding Common Share of the Company to
the shareholders of record on August 3, 1995, (the "Record Date"). Each Right
entitles the registered holder to purchase from the Company one one-hundredth of
one share of the Series A Preferred Shares (the "Preferred Shares"), or in some
circumstances, Common Shares, other securities, cash or other assets as
summarized below, at a price of $30.00 per share (the "Purchase Price"), subject
to adjustment. The description and terms of the Rights are set forth in a Rights
Agreement (the "Rights Agreement") between the Company and American Stock
Transfer and Trust Company, as Rights Agent.

The Shareholder Rights Plan was designed to reduce the likelihood of
inadequate bids, partial bids, market accumulations and front-end loaded offers
to acquire the Company's Common Shares, which are not in the best interest of
all the Company's shareholders. The adoption of the Plan communicates the
Company's intention to resist such actions as are not in the best interest of
all shareholders and provides time for the Board of Directors to consider any
offer and seek alternative transactions to maximize shareholder value. The Plan
was adopted upon the advice of the Company's investment bankers in 1995.

Until the earlier to occur of (i) the date of a public announcement
that a person or group of affiliated or associated persons (an "Acquiring
Person") acquired, or obtained the right to acquire, beneficial ownership of 20%
or more of the outstanding Common Shares or (ii) ten days following the
commencement or announcement of an intention to make a tender offer or exchange
offer that would result in a Person or group beneficially owning 20% or more of
such outstanding Common Shares (the earlier of such dates being called the
"Distribution Date"), the Rights will be evidenced, with respect to any of the
Company's Common Share certificates outstanding as of the Record Date, by such
Common Share certificate. The Rights Agreement provides that, until the
Distribution Date, the Rights will be transferred with and only with the Common
Shares. Until the Distribution Date (or earlier redemption or expiration of the
Rights), new Common Share certificates issued after the Record Date upon
transfer or new issuance of the Common Shares will contain a notation
incorporating the Rights Agreement by reference. Until the Distribution Date (or
earlier redemption or expiration of the Rights), the surrender for transfer of
any of the Company's Common Share certificates outstanding as of the Record,
will also constitute the transfer of the Rights associated with the Common
Shares represented by such certificate. As soon as practicable following the
Distribution Date, separate certificates evidencing the Rights ("Rights
Certificates") will be mailed to holders of record of the Common Shares as of
the close of business on the Distribution Date and such separate Rights
Certificates alone will evidence the Rights.

The Rights are not exercisable until the Distribution Date. The Rights
will expire on August 4, 2005, unless earlier redeemed by the Company as
described below.

The Purchase Price payable, and the number of Preferred Shares (or
Common Shares, other securities, cash or other assets, as may be necessary)
issuable upon exercise of the Rights are subject to adjustment from time to time
to prevent dilution (i) in the event of a stock dividend on, or a subdivision,
combination or reclassification of the Preferred Shares, (ii) upon the grant to
holders of the Preferred Shares of certain rights or warrants to subscribe for
Preferred Shares or convertible securities at less than the current market price
of the Preferred Shares or (iii) upon the distribution to holders of the
Preferred Shares of evidences of indebtedness or assets (excluding regular
periodic cash dividends out of earnings or retained earnings or dividends
payable in the Preferred Shares) or of subscription rights or warrants (other
than those referred to above).

In the event that the Company were acquired in a merger or other
business combination transaction of 50% or more of its assets or earning power
were sold, proper provision shall be made so that each holder of a Right, other
than of Rights that are or were beneficially owned by an Acquiring Person (which
will thereafter be void) shall thereafter have the right to receive, upon the
exercise thereof at the then current exercise price of the Right, that number of
common shares of the acquiring company which at the time of such transaction
would have a market value of two times the exercise price of the Right. In the
event that an Acquiring Person becomes the beneficial owner of 20% or more of
the outstanding Common Shares, proper provision shall be made so that each
holder of a Right, other than of Rights that are or were beneficially owned by
the Acquiring Person (which will thereafter be void), will thereafter have the
right to receive upon exercise that number of the Common Shares (or in certain
other circumstances, assets or other securities) having a market value of two
times the exercise price of the Right.

With certain exceptions, no adjustment in the Purchase Price will be
required until cumulative adjustments require an adjustment of at least 1% in
such Purchase Price. No fractional shares will be issued (other than fractional
shares which are integral multiples of one one-hundredth of one Preferred Share)
and, in lieu thereof, an adjustment in cash will be made based on the market
price of the Preferred Shares on the last Trading Date prior to the date of
exercise.

At any time prior to 5:00 P.M. Kansas City, Missouri time on the tenth
calendar day after the first date after the public announcement that a person or
group of affiliated or associated persons has acquired beneficial ownership of
20% or more of the outstanding Common Shares of the Company (the "Share
Acquisition Date"), the Company may redeem the Rights in whole, but not in part,
at a price of $0.005 per Right (the "Redemption Price"). Following the Share
Acquisition Date, but prior to an event listed in Section 13(a) of the Rights
Agreement, the Company may redeem the Rights in connection with any event
specified in Section 13(a) in which all shareholders are treated alike and which
does not include the Acquiring Person or his Affiliates or Associates.
Thereafter, the Company's right of redemption may be reinstated if an Acquiring
Person reduces his beneficial ownership to 10% or less of the outstanding Common
Shares in a transaction or series of transactions not involving the Company.
Immediately upon the action of the Board of Directors of the Company electing to
redeem the Rights, the Company shall make announcement thereof, and upon such
election, the right to exercise the Rights will terminate and the only right of
the holders of Rights will be to receive the Redemption Price.

Until a Right is exercised, the holder thereof, as such, will have no
rights as a shareholder of the Company, including, without limitation, the right
to vote or to receive dividends.

The provisions of the Rights Agreement may be amended by the Board of
Directors in order to cure any ambiguity or correct any defect or inconsistency,
extend the Redemption Period and, prior to the Distribution Date, to make
changes deemed to be in the best interests of the holders of the Rights or,
after the Distribution Date, to make such other changes which do not adversely
affect the interests of the holders of the Rights (excluding the interests of
any Acquiring Person and its affiliates and associates).

Certain Anti-takeover Provisions

The provisions of the Company's Certificate of Incorporation and
By-laws summarized in the following paragraphs may be deemed to have an
anti-takeover effect and may delay, defer, or prevent a tender offer or takeover
attempt that a shareholder might consider to be in that shareholder's best
interests, including attempts that might result in a premium over the market
price for the shares held by shareholders. In addition, certain provisions of
Delaware law and the Company's Long-Term Incentive Plan may be deemed to have a
similar effect.

Certificate of Incorporation and By-laws. The Board of Directors of the
Company is divided into three classes. The term of office of one class of
directors expires at each annual meeting of shareholders, when their successors
are elected and qualified. Directors are elected for three-year terms.
Shareholders may remove a director only for cause. In general, the Board of
Directors, not the Company's shareholders, has the right to appoint persons to
fill vacancies on the Board of Directors.

Pursuant to the Company's Certificate of Incorporation, the Company's
Board of Directors, by resolution, may establish one or more classes or series
of preferred shares having the number of shares, designation, relative voting
rights, dividend rates, liquidation and other rights, preferences, and
limitations that the Board of Directors fixes without any shareholder approval.
Any rights, preferences, privileges, and limitations that are established could
have the effect of impeding or discouraging the acquisition of control of the
Company.

The Company's Certificate of Incorporation contains a "fair price"
provision that requires the affirmative vote of the holders of at least 80% of
the voting shares of the Company and the affirmative vote of at least two-thirds
of the voting shares of the Company not owned, directly or indirectly, by the
Related Person (hereafter defined) to approve any merger, consolidation, sale or
lease of all or substantially all of the assets of the Company, or certain other
transactions involving any Related Person. For purposes of the fair price
provision, a "Related Person" is any person beneficially owning 10% or more of
the voting shares of the Company who is a party to the Transaction at issue, a
director who is also an officer of the Company and is a party to the Transaction
at issue, an affiliate of either such person, and certain transferees of those
persons. The voting requirement is not applicable to certain transactions,
including those that are approved by the Company's Continuing Directors (as
defined in the Certificate of Incorporation) or that meet certain "fair price"
criteria contained in the Certificate of Incorporation.

The Company's Certificate of Incorporation further provides that
shareholders may act only at an annual or special meeting of shareholders and
not by written consent, that special meetings of shareholders may be called only
by the Board of Directors, and that only business proposed by the Board of
Directors may be considered at special meetings of shareholders.

The Company's Certificate of Incorporation also provides that the only
business (including election of directors) that may be considered at an annual
meeting of shareholders, in addition to business proposed (or persons nominated
to be directors) by the directors of the Company, is business proposed (or
persons nominated to be directors) by shareholders who comply with the notice
and disclosure requirements of the Certificate of Incorporation. In general, the
Certificate of Incorporation requires that a shareholder give the Company notice
of proposed business or nominations no later than 60 days before the annual
meeting of shareholders (meaning the date on which the meeting is first
scheduled and not postponements or adjournments thereof) or (if later) 10 days
after the first public notice of the annual meeting is sent to common
shareholders. In general, the notice must also contain certain information about
the shareholder proposing the business or nomination, his interest in the
business, and (with respect to nominations for director) information about the
nominee of the nature ordinarily required to be disclosed in public proxy
solicitations. The shareholder must also submit a notarized

letter from each of his nominees stating the nominee's acceptance of the
nomination and indicating the nominee's intention to serve as director if
elected.

The Certificate of Incorporation also restricts the ability of
shareholders to interfere with the powers of the Board of Directors in certain
specified ways, including the constitution and composition of committees and the
election and removal of officers.

The Certificate of Incorporation provides that approval by the holders
of at least two-thirds of the outstanding voting shares is required to amend the
provisions of the Certificate of Incorporation discussed in the preceding
paragraphs and certain other provisions, except that approval by the holders of
at least 80% of the outstanding voting shares of the Company, together with
approval by the holders of at least two-thirds of the outstanding voting shares
not owned, directly or indirectly, by the Related Person, is required to amend
the fair price provisions and except that approval of the holders of at least
80% of the outstanding voting shares is required to amend the provisions
prohibiting shareholders from acting by written consent.

Delaware Anti-takeover Statute. The Company is a Delaware corporation
and is subject to Section 203 of the Delaware General Corporation Law. In
general, Section 203 prevents an "interested shareholder" (defined generally as
a person owning 15% or more of the Company's outstanding voting shares) from
engaging in a "business combination" (as defined in Section 203) with the
Company for three years following the date that person became an interested
shareholder unless (a) before that person became an interested shareholder, the
Board of Directors of the Company approved the transaction in which the
interested shareholder became an interested shareholder or approved the business
combination, (b) upon consummation of the transaction that resulted in the
interested shareholder's becoming an interested shareholder, the interested
shareholder owns at least 85% of the voting shares of the Company outstanding at
the time the transaction commenced (excluding shares held by directors who are
also officers of the Company and by employee stock plans that do not provide
employees with the right to determine confidentially whether shares held subject
to the plan will be tendered in a tender or exchange offer), or (c) following
the transaction in which that person became an interested shareholder, the
business combination is approved by the Board of Directors of the Company and
authorized at a meeting of shareholders by the affirmative vote of the holders
of at least two-thirds of the outstanding voting shares of the Company not owned
by the interested shareholder.

Under Section 203, these restrictions also do not apply to certain
business combinations proposed by an interested shareholder following the
announcement or notification of one of certain extraordinary transactions
involving the Company and a person who was not an interested shareholder during
the previous three years or who became an interested shareholder with the
approval of a majority of the Company's directors, if that extraordinary
transaction is approved or not opposed by a majority of the directors who were
directors before any person became an interested shareholder in the previous
three years or who were recommended for election or elected to succeed such
directors by a majority of such directors then in office.

Long-Term Incentive Plan. Awards granted pursuant to the Company's
Long-Term Incentive Plan may provide that, upon a change in control of the
Company, (a) each holder of an option will be granted a corresponding stock
appreciation right, (b) all outstanding stock appreciation rights and stock
options become immediately and fully vested and exercisable in full, and (c) the
restriction period on any restricted stock award shall be accelerated and the
restrictions shall expire.

Debt. Certain provisions in the Bank Facility and Subordinated Notes
may also impede a change in control, in that they provide that the loans become
due if there is a change in the management of the Company or a merger with
another company.

Item 6. Selected Financial Data.

Selected financial data as of the dates and for the periods indicated
is presented below. In 1995, the Company changed its method of accounting for
oil and gas operations from the full cost method to the successful efforts
method. The information provided below reflects this change for all periods.
This data also reflects a retroactive restatement for all periods presented to
reflect the merging of the Company's predecessor, Pan Petroleum MLP, into the
Company effective September 1, 1992 and reflects the acquisition of the West
Delta offshore properties as of May 28, 1991, accounted for utilizing the
"purchase" method.

Summary of Operations:

For the year ended December 31,
1996(a) 1995 1994 1993 1992
------- ---- ---- ---- ----

Oil and Gas revenue $ 20,063,000 18,447,000 17,338,000 12,605,000 13,335,000
Depreciation, depletion
& amortization 9,022,000 8,064,000 6,038,000 4,288,000 4,245,000
Lease operating expense 8,477,000 8,055,000 5,231,000 5,297,000 5,762,000
Production and ad valorem taxes 559,000 1,078,000 1,006,000 754,000 867,000
Exploration expenses --- 8,112,000 --- --- ---
Provision for losses and (gains)
on disposition and write-downs
of assets --- 751,000 1,202,000 3,824,000 ---
West Delta fire loss 500,000 --- --- --- ---

Net operating income (loss) 733,000 (8,303,000) 3,274,000 (2,100,000) 1,922,000

Gain/(loss) on investment
in common stock (258,000) --- --- --- ---
Interest expense (net) 2,514,000 987,000 1,623,000 1,886,000 2,323,000

Net income (loss) (2,039,000) (9,290,000) 1,115,000 (3,986,000) (401,000)

Net income (loss) per
Common Share $ (0.16) (0.81) 0.11 (0.53) (0.05)

Summary Balance Sheet Data:

Oil and Gas Properties, pipelines
and equipment (net) 61,150,000 29,485,000 23,945,000 19,183,000 26,448,000
Total assets 73,768,000 36,169,000 29,095,000 24,432,000 31,085,000
Long-term debt 49,500,000 22,390,000 12,500,000 12,465,000 15,380,000
Stockholders' equity 17,498,000 9,174,000 14,882,000 8,744,000 11,700,000
Dividends per Common Share $ 0.00 0.00 0.00 0.00 0.00

(a) Results for the period ended December 31, 1996, were substantially affected
by the explosion and fire. See "Recent Explosion and Fire". Such results include
the results of operations through August 31 for the Bayou Sorrel Field, which
was sold effective September 1, 1996, and the results of operations of the Amoco
Properties from after October 8, 1996, their date of acquisition.

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

For the years ended December 31, 1996 and 1995:

General

The oil and gas industry has experienced significant volatility in recent
years because of the fluctuatory relationship of the supply of most fossil fuels
relative to the demand for such products and other uncertainties in the world
energy markets. These industry conditions should be considered when this
analysis of the Company's operations is read.

The Company experienced an explosion and fire on April 24, 1996 at Tank
Battery #3 in West Delta resulting in the fields being shut-in from April 24th,
until being returned to production on October 7, 1996. The loss of 67 days of
production in the second quarter and the entire third quarter resulted in lost
revenues estimated by management to be approximately $6,000,000. During the
second quarter the Company expensed $500,000 for its loss as a result of this
explosion. No further losses have been recognized or are anticipated. This
$500,000 amount included $225,000 in deductibles under the Company's insurance.

The Company has spent $8,500,000 on Tank Battery #3 inclusive of the
$500,000 expensed during second quarter and has received reimbursement from its
insurance company of $3,900,000, after satisfaction of the $225,000 in
deductibles. The excess of expenditures over insurance reimbursement has been
capitalized. No additional expenditures have been made or are anticipated. The
Company is planning to file suits against the employers of the persons who
caused the incidents for recovery of these costs and its lost profits. No
assurance can be given that the Company will successfully recover any amounts
sought in any such suits.

Results of Operations

"Oil and Gas revenue" increased 8% for the year ended December 31, 1996
when compared to the year ended December 31, 1995, in spite of the explosion and
fire at West Delta. The fire and explosion substantially reduced oil and natural
gas production for 1996, as production from the West Delta Fields was shut-in
from the day of the explosion and fire (April 24, 1996) until October 7, 1996.
The decrease in production from West Delta was offset by production from
properties acquired. The Amoco Properties, acquired on October 8, 1996, and the
Bayou Sorrel Field, acquired on December 28, 1995 had no production realized by
the Company in 1995. The offshore properties of Zapata Exploration Company were
acquired on July 26, 1995 with the production from these properties being
included in the Company's results of operations from July 27 through December
31, 1995. Although production increased in 1995 over 1994, primarily due to the
acquisition of the Zapata Properties in July 1995, a drop in natural gas prices
offset most of the benefit of the increased production.

Production. Natural gas production decreased 31% to 6,788,000 Mcf in 1996
from 9,850,000 Mcf in 1995. Natural gas production from West Delta decreased
from 7,825,000 Mcf in 1995 to 2,058,000 Mcf for the same period in 1996,
primarily a result of the explosion and fire on April 24, 1996. A secondary
factor in the decrease in West Delta production was a decline in 1996 production
from four horizontal wells drilled in 1994. These four wells produced more
natural gas in January to April, 1995 than they did for the same period in 1996
(in the period prior to the explosion and fire). Natural gas production,
primarily from the Zapata and the Amoco Properties, and the Bayou Sorrel Field
(primarily an oil field), somewhat offset the decrease in West Delta production.
The increase in Zapata production realized by the Company is due to the fact
that they were acquired on July 26, 1995. The production from these properties
included in the year ended December 31, 1995 is only from July 27 to December
31, while the production for the full year is included in 1996. The Zapata
acquisition

was the primary factor in natural gas production increasing 21% to
9,850,000 Mcf in 1995 over 1994.

Oil production from the West Delta Fields also decreased for the year
ended December 31, 1996 when compared to the same period in 1995, from 132,000
barrels to 57,000 barrels. However, as with natural gas, acquisitions offset the
decrease from West Delta. The Bayou Sorrel Field, which produces primarily oil,
produced 93,000 barrels in 1996 which, along with the Amoco Properties, had no
oil production realized by the Company in 1995, more than offsetting the
decrease from West Delta. Also, oil production from the Zapata Properties is
included for the full year in 1996, with only the period of July 27 to December
31 included in the same period of 1995, due to the July 26 acquisition date,
also offsetting the decrease from West Delta. These factors resulted in a 62%
increase in oil production, from 170,000 barrels in 1995 to 276,000 barrels in
1996. Oil production in 1995 increased 24% over 1994, also primarily as a result
of the Zapata acquisition in July 1995.

On an Mcf equivalent basis, total oil and natural gas production decreased
22% in 1996 when compared to 1995, and increased 21% in 1995 over 1994.

Prices. Natural gas prices increased in 1996 to $2.75 per Mcf compared to
$1.58 in 1995. The Company entered into a natural gas swap agreement beginning
January 1, 1996 for the sale of 15,000 MMBtu of gas each day in 1996, with
contract prices ranging from $1.75 per MMBtu to $2.25 per MMBtu. A swap loss for
the year ended December 31, 1996 of $3,900,000, decreased the net price received
by the Company to $2.17 per Mcf for the year. Natural gas prices dropped to the
$1.58 in 1995 from $1.88 in 1994, offsetting most of the benefit from increased
production in 1995.

Oil prices also increased, from $15.35 per barrel in 1994 to $16.78 per
barrel in 1995 and to $19.42 per barrel in 1996.

"Depletion, depreciation and amortization" increased 12% in 1996 despite
the reduced production from the West Delta Fields (See the discussion of
production volumes in "Oil and Gas Revenue"). While the production from
properties acquired accounted for a part of the 12% increase, depletion,
depreciation and amortization per Mcf equivalent also increased, from $0.74 in
1995 to $1.07 in 1996, due to year-end 1996 engineering revisions from Ryder
Scott on the West Delta and East Breaks 109/110 Fields, and production from the
Amoco Properties in the fourth quarter of 1996, which had higher depletion rates
per Mcf equivalent than previously owned properties. The 34% increase in 1995
was also a result of the Zapata acquisition for $2,700,000 and an increase in
production, bringing about an increased rate of depletion.

"Lease operating expenses" increased $422,000 in 1996 primarily due to the
Amoco, Zapata and Bayou Sorrel Field acquisitions. With the Zapata Properties,
the Company acquired interests in five offshore producing properties. Since the
acquisition of the Zapata Properties closed on July 26, 1995, only the lease
operating expenses from July 27, to December 31, 1995 are included in the 1995
results of operations, while the 1996 period includes these expenses for the
full year. 1996 also includes eight months of lease operating expenses for the
Bayou Sorrel Field (sold September 1) and almost three months (October
8-December 31) of the Amoco Properties, with none of these expenses included in
1995. West Delta lease operating expenses did decrease in 1996 ($805,000 from
expected levels) with the fields being shut-in from April 25 through October 7,
however, a part of these lease operating expenses are fixed in nature and
continued. These expenses increased significantly in 1995 over 1994 by (1)
$1,008,000 related to the acquisition of the Zapata Properties in July which
added interests in six offshore platforms and 44 wells, (2) $1,105,000 of
additional operating expenses on the West Delta Properties required to maintain
production from some of the more rapidly declining wells, and (3) $711,000 of
expensed items which might have otherwise have been capitalized.

"Production and ad valorem taxes" decreased to 2.8% of oil and natural gas
sales in 1996 from 5.8% of oil and natural gas sales in 1995.The decrease is
primarily due to the shift in the Company's production volumes from properties
subject to severance taxes to properties in federal offshore waters (the Amoco
and Zapata Properties) that are not subject to such taxes. A part of the
decrease ($178,000 from expected levels) is also due to the lost production from
the West Delta Properties for 67 days in the second quarter and the entire third
quarter due to the explosion and fire. A large percentage of this production is
in Louisiana State waters which are subject to severance taxes.

"Exploration expenses" in 1995 consisted of dry hole exploratory costs of
$796,000 on Eugene Island Block 50, $1,378,000 on South Timbalier Block 33,
(both drilled during the second quarter of 1995), and $5,938,000 on West Delta
Block 54 (drilled during the fourth quarter of 1995). The Company currently
plans no further exploratory activity on these blocks.

"Provision for write-downs of assets" in 1995 was related to the group of
onshore properties, acquired in the early 1980's which were becoming a less
significant part of its operations.

"West Delta fire loss" is the expense of the explosion and fire at Tank
Battery # 3, the central processing facility for the West Delta Fields. Included
in this expense is the insurance deductibles and the cost of non- reimbursed
expenditures which were not capitalized.

"Gain/(loss) on investment in common stock" in 1996 was a result of a
decrease in the market value at December 31, 1996 of 477,612 shares of National
Energy Group, Inc. common stock received in connection with the sale of the
Bayou Sorrel Field.

"Net operating income (loss)" increased significantly in 1996 as a result
of the $8,100,000 exploration expenses and the $751,000 onshore property
write-down incurred in 1995. Of the $8.1 million in exploration expenses in
1995, $5,900,000 was incurred in the fourth quarter in the drilling of a dry
exploratory well in West Delta Block 54. The $5,900,000 exploration expense,
along with the $751,000 property write down, also incurred in the fourth
quarter, were the primary contributors to the net operating loss of $8,300,000
in 1995.

"Interest expense (net)" increased $1,500,000 , or 155% in 1996 when
compared to 1995. Average Long- Term Debt levels increased from $11,000,000 in
1995 to $28,000,000 for 1996, resulting in the primary cause of the increase in
interest expense. On December 27, 1995 the Company borrowed $10,000,000 in
connection with the Bayou Sorrel Field acquisition. Through April, 1996, the
Company had begun to aggressively reduce Long-Term Debt, and it had reduced it
by $4,000,000. The April 24th explosion and fire at West Delta reduced the
Company's discretionary cash flows and restricted the Company's ability to
continue to lower its Long-Term Debt. On October 8, 1996, the Company completed
its acquisition of oil and gas assets from Amoco Production Company. The cash
portion of the $40,400,000 purchase price ($32,000,000) was funded by long-term
debt. The Company borrowed $17,000,000 from lenders advised by Kayne, Anderson
Investment Management, Inc., bearing interest at 12%. The remaining $15,000,000
in cash paid to Amoco was funded under the Company's bank facility, bearing
interest at approximately 7.25%. These were the primary factors in the Company's
average borrowing levels being higher in 1996 versus 1995. The weighted average
interest rate incurred in 1996 was 8.9%, relatively flat with the 8.6% in 1995.
The decrease in interest expense in 1995 from 1994 was a result of the lower
average long-term debt levels that prevailed throughout most of the year.

Sale of Bayou Sorrel

Effective September 1, 1996, the Company sold its Bayou Sorrel Field to
National Energy Group, Inc. for 38

$9,000,000 in cash and 477,612 shares of National Energy Group, Inc. common
stock. The Company also retained an overriding royalty interest in the deep
rights of the field for depths below 11,000'. The field was acquired by the
Company from Shell Western E.P., Inc. for $10,500,000 on December 28,1995, which
included a broker's fee and a related receivable. During the eight months the
Company owned the field two wells were drilled which did not result in
production in commercial quantities. The Company received an offer to purchase
the field. After having made the Amoco Acquisition, Management believed that the
Company's resources could be better utilized elsewhere. The effective date of
the sale was September 1, 1996, the date at which National Energy Group, Inc.
assumed all benefits and liabilities of owning the property. The Company did not
record a gain or loss on the sale. For the year ended December 31, 1996, the
Bayou Sorrel Field accounted for $2,000,000, or 10% of the Company's total oil
and gas revenue. The Field had also accounted for $733,000, or 9% of lease
operating expenses, $888,000, or 10% of depreciation, and amortization and
$239,000 or 43% of production and ad valorem taxes. The net results of the field
contributed $150,000 to operating income, or 20%. The purchase price was paid in
cash, borrowed on the Company's Bank Facility. The estimated interest expense
incurred in 1996 by owning the field totaled $588,000. The operating income of
the field and interest expense incurred resulted in a decrease in net income of
$438,000.

Liquidity and Capital Resources

At December 31, 1996, 82% of the Company's total assets were represented
by oil and gas properties, pipelines and equipment, net of accumulated
depreciation, depletion and amortization.

On October 8, 1996, the Company amended its bank facility with First Union
National Bank of North Carolina (60% participation), and Banque Paribas (40%
participation), herein "Bank Facility". The loan is a reducing revolver designed
to provide the Company up to $40,000,000 depending on the Company's borrowing
base, as determined by the lenders. The Company's borrowing base at December 31,
1996 was $31,000,000, with an availability under the revolver of $2,500,000. The
principal amount of the loan is due July 1, 1999. However, at no time may the
Company have outstanding borrowings under the Bank Facility in excess of its
borrowing base. Interest on the loan is computed at the bank's prime rate or at
1 to 1 3/4% (depending upon the percentage of the facility being used) over the
applicable London Interbank Offered Rate ("LIBOR") on Eurodollar loans.
Eurodollar loans can be for terms of one, two, three or six months and interest
on such loans is due at the expiration of the terms of such loans, but no less
frequently than every three months. Management feels that this bank facility
greatly enhances its ability to make necessary capital expenditures to maintain
and improve production from its properties and makes available to the Company
additional funds for future acquisitions. The bank facility is collateralized by
a first mortgage on the Company's offshore properties. The loan agreement
contains certain covenants including a requirement to maintain a positive
indebtedness to cash flow ratio, a positive working capital ratio, a certain
tangible net worth, as well as limitations on future debt, guarantees, liens,
dividends, mergers, material change in ownership by management, and sale of
assets. With the proceeds from the recently completed Common Share offering, on
March 6, 1997, it temporarily repaid $8,500,000 on this bank facility, which
funds will ultimately be used for the development of its properties and future
acquisitions.

(a) 1993 Subordinated Notes. In 1993, $5,000,000 was borrowed, due December
31, 1999. These Notes were prepaid on March 6, 1997, with a portion of the
proceeds of the Company's recent Common Share offering. The lenders were issued,
and during 1996 exercised, warrants to acquire 816,526 Common Shares at $2.25
per share.
(b) 1996 Tranche A Convertible Subordinated Notes. On October 8, 1996,
$8,500,000 was borrowed, due October 8, 2003, but prepayable any time after May
8, 1998. After August 28, 1997 the Notes are convertible into 2,060,606 Common
Shares on the basis of $4.125 per share. The Company may deliver up to
$2,000,000 in PIK notes in satisfaction of interest payment obligations.

(c) 1996 Tranche B Bridge Loan Subordinated Notes. On October 8, 1996,
$8,500,000 was borrowed, due October 8, 2003. These Notes were prepaid on March
6, 1997, with a portion of the proceeds of the Company's recent Common Share
offering.

In 1991, in connection with a debt financing which has subsequently been
repaid, certain former lenders received a net profits interest (NPI) in the West
Delta Properties, which is a continuing obligation with respect to these
properties. During the three months ended March 31, 1996, payments with respect
to this NPI averaged $53,000 per month. Due to the explosion and fire at Tank
Battery #3, no NPI payments were made in the remaining months of 1996.

Pursuant to existing agreements the Company is required to deposit funds
in bank trust and escrow accounts to provide a reserve against satisfaction of
its eventual responsibility to plug and abandon wells and remove structures when
certain fields no longer produce oil and gas. Each month, until November 1997,
$25,000 is deposited in a bank escrow account, to satisfy such obligations with
respect to a portion of its West Delta Properties. The Company has entered into
an escrow agreement with Amoco Production Company under which the Company will
deposit, for the life of the fields, in a bank escrow account ten percent (10%)
of the net cash flow, as defined in the agreement, from the Amoco properties.
The Company has established the "PANACO East Breaks 110 Platform Trust" in favor
of the Minerals Management Service of the U.S. Department of the Interior. This
trust requires an initial funding of $846,720 in December 1996, and remaining
deposits of $244,320 due at the end of each quarter in 1999 and $144,000 due at
the end of each quarter in 2000 for a total of $2,400,000. In addition, the
Company has $9,250,000 in surety bonds to secure its plugging and abandonment
obligations; including a $4,100,000 bond which was provided to the original
sellers of the West Delta Properties; a $2,400,000 supplemental bond provided to
the Minerals Management Service of the U.S. Department of the Interior in
connection with the plugging and structure removal obligations for the Company's
East Breaks Block 110 Platform and a $300,000 Pipeline Right-of-Way Bond.

During 1996 the Company hedged the price of natural gas by selling the
equivalent of 15,000 MMBtu per day for 1996 at fixed prices which ranged from a
high of $2.25 in January to a low of $1.75 in July. When the closing price
(settlement price) on NYMEX for natural gas futures was greater than the swap
price for a given month the Company paid that difference to the bank which
effected the swap. If the settlement price was less than the swap price the bank
paid that difference to the Company. By entering into the swap in December 1995
the Company locked in the fixed prices on 15,000 MMBtu per day for each month in
1996. Since the Company sells its natural gas on the spot market, in 1996 it
realized prices which approximated the settlement prices on NYMEX, less
differences for transportation due to pipeline locations that are varying
distances from Henry Hub, Louisiana which is the delivery point used for natural
gas futures on NYMEX. Starting in 1997 the Company's hedge transactions on
natural gas are based upon published gas pipeline index prices and not the
NYMEX. This change has eliminated the possibility of price differences due to
transportation. For 1997, 14,000 MMBtu's per day has hedged, reduced to 10,000
MMBtu's per day in 1998 and 7,000 MMBtu's per day in 1999. The

Company is hedging at a swap price of $1.80 per MMBtu for 1997, with varying
levels of participation (93% in January of 1997 to 40% in September) in
settlement prices above to $1.80 per MMBtu swap price level. Management has
generally used hedge transactions to protect its cash flows when the Company's
borrowings under long-term debt have been higher and refrained from hedge
transactions when long-term debt has been lower. For accounting purposes, gains
or losses on swap transactions are recognized in the production month to which a
swap contract relates.

Despite a 22% decrease in production and a net loss of $2,000,000 in 1996,
strong product prices contributed significantly to cash flows provided by
operations of $8,000,000. While 1995 prices were lower, record production offset
this decrease, providing cash flows of $8,400,000 in 1995.

In 1996, the Company sold its Bayou Sorrel Field, the cash proceeds from
the sale being $9,000,000 along with 477,612 shares of National Energy Group,
Inc. common stock. The Company incurred a record $43,000,000 in capital
expenditures (excluding the 2,000,000 Common Shares to Amoco Production Company)
in 1996, primarily for the Amoco acquisition in October and $4,000,000 spent to
repair and rebuild Tank Battery #3 in the West Delta Fields. The 1995 capital
expenditures of $22,000,000 included the Zapata and Bayou Sorrel Field
acquisitions and $8,000,000 in exploratory drilling costs. The 1994 capital
expenditures were primarily for developmental work in the West Delta Fields.

Along with increasing capital expenditures, the Company's borrowings have
also increased each year. Borrowings increase in 1996 to fund capital
expenditures, which included the repair and rebuilding of Tank Battery #3 in
West Delta. The explosion and fire, which necessitated the repair and
rebuilding, decreased discretionary cash flows, limiting the Company's ability
to repay long-term debt. The repayments in 1996 include $4,000,000 repaid
through April with cash provided by operations and $6,000,000 from the cash
proceeds from the sale of the Bayou Sorrel Field. The Company received cash and
increased stockholders' equity by $1,800,000 in 1996, $3,200,000 in 1995 and by
$5,000,000 in 1994 by virtue of the exercise of stock options and warrants.

Capital Spending

In 1996 the Company made $51,000,000 in total capital expenditures,
including (1) $40,400,000 on the purchase of oil and gas assets from Amoco
Production Company, which included $8,400,000 of the Company's common stock, (2)
$4,000,000 for repair and rebuilding of the West Delta Tank Battery #3, net of
insurance reimbursements, and (3) $4,700,000 for development of its oil and gas
properties. The majority of the development costs were incurred to drill two
unsuccessful development wells in the Bayou Sorrel Field and for the Company's
share of successfully recompleting two wells on Eugene Island Block 372, which
is operated by Unocal Corporation.

For the years ended December 31, 1992 - December 31, 1994

Results of Operations

"Oil and Gas revenue" during the years ended December 31, 1992 through
1994 has varied due to several factors. The prices of oil and gas have
fluctuated widely during the years shown. Oil prices are influenced by world
political events as well as decisions made by OPEC regarding the production
quotas of its members. Prices are further influenced by world economic
conditions which affect industrial output and the need for oil.

1992 was the first full year of owning the West Delta Fields, purchased
in 1991, while 1992 and 1993 production for the Company remained relatively
flat. Mcf equivalent production was 6,855,000 in 1992 and

6,666,000 in 1993. In 1994 the Company drilled four successful horizontal wells
in the West Delta Fields, substantially increasing production to 8,961,000 Mcf
equivalent in that year.

The average natural gas price received by the Company has fluctuated
but generally followed the trend of national gas prices. Gas revenue increased
as a percentage of the Company's revenue from 75% in 1992 to 88% in 1994. While
production reached a record high in 1994, natural gas prices dropped to a low
for the three year period of $1.88 per Mcf from $2.24 in 1993 and $1.92 in 1992.

From time to time, upon the insistence of its bank lenders the Company
has entered into natural gas hedging agreements which have the effect of raising
or lowering the price it receives for natural gas. In 1992, a contract loss of
$1,100,000 lowered the average price received per Mcf by $.19 to $1.73. In 1993,
a contract loss of $3,000,000 lowered the average price received per Mcf by $.52
to $1.72.

In 1994, the Company sold 137,000 barrels of oil for an average of
$15.35 per barrel accounting for 12% of oil and gas revenue. In 1993, oil was
24% of such revenue with 180,000 barrels at an average price of $16.68. In 1992,
oil was 25% of such revenue with 174,000 barrel at an average price of $19.41.

A large part of the changes affecting most operating accounts in 1992
was due to West Delta being operated for twelve months compared with only seven
months in 1991.

"Depreciation, depletion and amortization" increased in 1994 due to the
1994 drilling and rework program increasing capitalized cost and the 34%
increase in production. The expense for 1993 remained relatively constant over
1992 with only a slight decrease due to lower production.

"Lease operating expense" remained relatively flat throughout the three
year period overall. On an Mcf equivalent basis, was lower in 1994 at $.58 per
1994 due to the increased production in that year from $.84 per Mcf equivalent
in 1992 and $.79 per Mcf in 1993.

"Production and ad valorem taxes" increased 33% in 1994 due to
increased production from four horizontal wells drilled in state waters on the
West Delta Properties in 1994.

"Provision for write-downs of assets" in 1993 and 1994 were for the
Company's group of onshore properties, acquired in the early 1980's which were
becoming a less significant part of its operations.

"Net operating income (loss)" increase in 1994 was due to the increased
production in that year, along with $2,600,000 lower asset write-downs brought
about the large increase in 1994. The operating income for 1993 decreased due to
lower production, and an asset write-down of $3,800,000.

"Interest expense (net)" decreases of 19% in 1993 and 13% in 1994 were
due to the significant decrease in long-term debt from 1992 levels and the
refinancing of such debt on July 1, 1994 at lower interest rates. The average
debt outstanding in 1994 was $14,000,000 with a weighted average interest rate
of 11.5% versus average debt outstanding of $14,000,000 and a weighted average
interest rate of 14% in 1993. Interest expense in 1992 had increased
significantly because of the debt incurred to acquire the West Delta Properties,
purchased in 1991. The average debt outstanding in 1992 was $17,000,000 with a
weighted average interest rate of 14%.

"Net income (loss) per common share" is based upon the weighted average
number of shares outstanding of 10,039,042 for 1994, 7,583,761 for 1993 and
7,314,041 for 1992.

Liquidity and Capital Resources

Cash flow from operations was used to reduce long term debt, drill
wells, recomplete wells and acquire properties.

On July 1, 1994 the Company entered into a Credit Agreement with the
First Union National Bank of North Carolina. The loan was a reducing revolver
designed to provide the Company up to $30,000,000 depending upon the Company's
borrowing base. The principal amount of the loan was due July 1, 1998.

During the last part of 1993 the Company increased Stockholders' Equity
$1,163,000, primarily by virtue of options and warrants being exercised. During
1994, the Company increased Stockholders' Equity $5,023,000, primarily as the
result of such exercises of options and warrants. At year-end 1993, the Company
issued the 1993 Subordinated Notes. The Company utilized this $5,000,000, along
with equity proceeds and cash flow from operations described above, to drill the
wells and perform the recompletions in 1994 and 1995.

Capital Spending

During 1994 the Company spent over $11,749,000 on eight offshore
recompletions and the drilling of four horizontal wells. All four horizontal
wells and all eight recompletions in 1994 were successful and offshore natural
gas production increased significantly.

Item 8. Financial Statement and Supplementary Data.

The financial statements are included herein beginning at page F-1. The
table of contents at the front of the financial statements lists the financial
statements and schedules included therein.

Item 9. Changes in and disagreements with Accountants on accounting and
Financial Disclosure.

None.

Item 10. Directors and Executive Officers of the Registrant.

The Company has a classified Board of Directors. Directors are elected
to serve for three-year terms and until their successors are elected and
qualified. One-third of the directors stand for election each year as their
terms expire. The Board of Directors consists of three employees of the Company
and six independent directors.

Officers are elected by and serve at the discretion of the Board of
Directors.

Set forth below are the names, ages, and positions of the persons who
are executive officers and directors of the Company, and the committees of the
Board on which they serve.

Director
Name Age Since Position

H. James Maxwell.......... 52 1992 Chairman of the Board, President,
Chief Executive Officer,and Director(a)
Bob F. Mallory............ 64 1992 Chief Operating Officer, Executive
Vice President and Director- Executive
and Personnel Committee (a)
Larry M. Wright........... 52 1992 Executive Vice President and
Director-Executive and Personnel
Committee (b)
Robert G. Wonish.......... 43 --- Vice President

Edward A. Bush, Jr........ 53 --- Vice President

William J. Doyle.......... 45 --- Vice President

Todd R. Bart.............. 32 --- Chief Financial Officer, Secretary and
Treasurer
A. Theodore Stautberg, Jr. 50 1993 Director(c)-Compensation Committee

Donald W. Chesser......... 57 1992 Director(a)

James B. Kreamer.......... 57 1993 Director(c)

N. Lynne Sieverling....... 59 1992 Director(b)-Audit and Compensation
Committees
Mark C. Barrett........... 46 1996 Director(b)-Audit and Compensation
Committees
Michael Springs........... 47 1996 Director(c)-Audit Committee

(a) These persons are designated as Class III directors, with their term of
office expiring at the annual meeting of shareholders in 1998.
(b) These persons are designated as Class II directors, with their term of
office expiring at the annual meeting of shareholders in 1997.
(c) These persons are designated as Class I directors, with their term of
office expiring at the annual meeting of shareholders in 1999.

Set forth below are descriptions of the principal occupations, during
at least the past five years, of the directors and executive officers of the
Company.

H. James Maxwell received a B.A. degree in Economics from the University of
Missouri-Kansas City and received his Law Degree from that same university in
1972. Mr. Maxwell practiced securities law from 1972 to 1984, and was a frequent
author and speaker on oil and gas tax and securities law. He served as a General
Partner of Castle Royalty Limited Partnership from 1984 to 1988, Managing
General Partner of PAN Petroleum MLP from 1987 to 1992, both of which were
predecessors of the Company, and President, CEO and Chairman of the Company from
1992 to date.

Bob F. Mallory received his Ph.D. in Geology from the University of
Missouri in 1968 and a B.A. in Geology from the University of Wichita in 1961.
He began consulting in the oil industry in 1980. He served as a General Partner
of Castle Royalty Limited Partnership from 1984 to 1988, as a General Partner of
PAN Petroleum MLP from 1987 to 1992, both of which were predecessors of the
Company, and Executive Vice President and Chief Operating Officer of the Company
from 1992 to date.

Larry M. Wright received his B.S. Degree in Engineering from the University
of Oklahoma in 1966. From 1966 to 1976 he was with Union Oil Company of
California (UNOCAL). From 1976 to 1980, he was with Texas International
Petroleum Corporation, ultimately as division operations manager. From 1980 to
1981, he was with what is now Transamerica Natural Gas Company as Vice
President-Exploration and Production. From 1981-1982, he was Senior Vice
President of Operations for Texas International Petroleum Corporation, and, from
1983 to 1985, he was Executive Vice President of Funk Fuels Corp., a subsidiary
of Funk Exploration. From 1985 to 1993, Mr. Wright was an independent
consultant. From 1993 to date, he has served as Executive Vice President of the
Company.

Robert G. Wonish received his B.S. in Mechanical Engineering in 1975 from
the University of Missouri-Rolla. He was a production engineer with Amoco from
1975 to 1977, Napeco, Inc. from 1977 to 1979; Division Operation Engineer with
Texas International from 1979 to 1980; Production Manager with Cliffs Drilling
Company from 1980 to 1984 and District Superintendent with Ladd Petroleum
Corporation from 1985 to 1991. He then worked as a consultant, starting with the
Company in 1992, and became an employee in 1993, serving as Vice President -
Production.
Edward A. Bush received his B.S. Degree in Geology from Baldwin Wallace
College in 1964 and his M.A. in Geology from Bowling Green State University in
1966. He served in various geological and exploration capacities with Exxon
(1968-75), Union Texas Petroleum (1975-79), Home Petroleum Corp. (1979-81),
Traverse Oil Co. (1981-83) and Sohio Petroleum Co. (1983-85). From 1985 to 1995
he served first as Exploration Manager, then Vice President of Exploration and
later Vice President of Operations for Columbia Gas Devp. Corp. From 1995 to
1996 he served as Vice President-Exploration and then the President of Howell
Petroleum Corp.

William J. Doyle received his Masters in Geology in 1975 from Texas A&M
University and his B.S. in Earth Sciences from the University of New Orleans in
1973. From 1975 to 1978 he was a geologist with Mobil Oil focusing on offshore
Gulf of Mexico projects. From 1978 to the present he has worked as an employee
and consultant for various oil and gas exploration companies operating in the
Gulf Coast. He joined the Company as a consulting geologist in 1992 and became a
Vice President in 1995.

Todd R. Bart received his B.B.A. in Accounting from Abilene Christian
University in 1987. He worked in the energy industry with Pennzoil Company from
1987 to 1990 and the public accounting firm of Arthur Andersen and Company from
1990 until 1992. From 1992 to 1995 he worked for Yellow Freight System, Inc., a
trucking company, in financial accounting and reporting. He joined the Company
as Controller in 1995 and was elected Chief Financial Officer, Treasurer and
Secretary in 1996. He received his C.P.A. designation in Texas in 1990 and in
Kansas in 1993, and is a member of the A.I.C.P.A.

A. Theodore Stautberg, Jr. has since 1981 been the President and a director
of Triumph Resources Corporation and its parent company, Triumph Oil and Gas
Corporation of New York. Triumph engages in the oil and gas business, assists
others in financing energy transactions, and serves as general partner of
Triumph Production L.P. Mr. Stautberg is also the president of Triumph
Securities Corporation and BT Energy Corporation. Prior to forming Triumph in
1981, Mr. Stautberg was a Vice President of Butcher & Singer, Inc., an
investment banking firm, from 1977 to 1981. From 1972 to 1977, Mr. Stautberg was
an attorney with the Securities and Exchange Commission. Mr. Stautberg is a
graduate of the University of Texas and the University of Texas School of Law.

Donald W. Chesser received his B.B.A. in Accounting from Texas Tech
University in 1963 and has served with several CPA firms since that time,
including eight years with Elmer Fox and Company. From 1977 to 1981,

he was with IMCO Enterprises, Inc. Since 1982 he has been a shareholder and
President of Chesser & Company, P.A., a CPA firm. He is also President of
Financial Advisors, Inc., a registered investment advisor.

James B. Kreamer received his B.S. Degree in Business from the University
of Kansas in 1963 and has been active in investment banking since that time.
Since 1982 he has managed his personal investments.

N. Lynne Sieverling received his B.S. Degree in Accounting from the
University of Kansas in 1959 and has practiced as a CPA since graduation,
serving 17 years as a partner with the accounting firm of Coopers & Lybrand. Mr.
Sieverling has also been actively involved in the oil and gas industry since
1984 both as an investor and as an operator of oil and gas leases in Kansas,
Oklahoma and North Dakota.

Mark C. Barrett received his B.S. Degree in Business
Administration/Accounting in 1972 and is licensed to practice as a Certified
Public Accountant in both Kansas and Missouri. He was a partner in the firm
Drees Dunn Lubow and Company from 1974 until 1981. He founded Barrett &
Associates, a CPA firm, in 1981 and is the president and majority shareholder in
that firm. His CPA firm served as the Company's independent public accountants
from 1985 to 1995.

Michael Springs graduated from the Medical Field Service School, Brooke
Hospital, San Antonio, Texas in 1971 and the University of Missouri, Kansas
City, in 1969 with a degree in Business. He is the President and founder of
Ortho-Care, Inc. of Kansas City, Missouri and Ortho-Care Southeast of Charlotte,
North Carolina. Ortho-Care, Inc. is a manufacturer of orthopedic fracture
management and sports medicine products, and holds a number of patents in the
field. Mr. Springs is also controlling partner in Ortho-Implants, a distributor
of total joint replacement prosthesis.

None of the officers or directors serve pursuant to employment
agreements.

Board of Directors

The Board of Directors has the responsibility for establishing broad
corporate policies and for the overall performance of the Company, although it
is not involved in day-to-day operating details. Directors are kept informed of
the Company's business by various reports and documents, as well as by operating
and financial reports presented at Board and committee meetings by the Chairman
and other officers.

Meetings of the Board of Directors are held regularly each quarter and
there is also a meeting following the annual meeting of the shareholders.
Additional meetings, including meetings by telephone conference call, of the
Board may be called whenever needed. The Board of Directors of the Company held
seven (7) meetings in 1996, four of which were meetings by telephone conference
call. Each director attended all meetings of the Board, except Donald W. Chesser
who failed to attend two meetings. With respect to the telephone conference
calls, Donald W. Chesser was not connected two times and James B. Kreamer and
Alan H. Sweeney (a then director) were not connected on one conference call.

Committees of the Board

The committees established by the Board of Directors to assist it in
the discharge of its responsibilities are described below. The previous table
identifies the committee memberships currently held.

The Executive Committee has three members, all of whom are also
officers of the Company. The Committee meets on call whenever needed and has
authority to act on most matters during the intervals between

Board meetings. The Executive Committee also serves as the Personnel Committee.

The Audit Committee has three members, none of whom is an employee of
the Company. The Committee meets with management to consider the adequacy of the
internal controls of the Company and the objectivity of its financial reporting;
the Committee also meets with the independent accountants concerning these
matters. The Committee recommends to the Board the appointment of the
independent accountants, subject to ratification by the shareholders at the
annual meeting. The independent accountants periodically meet alone with the
Committee and have unrestricted access to the Committee. The Committee met once
in 1996.

The Compensation Committee has three members, none of whom is an
employee of the Company. It makes recommendations to the Board with respect to
the compensation of management of the Company and the Company's Long-Term
Incentive Plan. The Committee met twice in 1996.

Compensation of Directors

Non-employee directors receive travel expenses incurred and $1,000 in
Common Shares for attending Board of Directors meetings, $500 in Common Shares
for attending committee meetings and $200 in Common Shares for telephone
meetings. Officers of the Company who serve as directors do not receive special
compensation for serving on the Board of Directors or a committee thereof.
During 1995 Messrs. Stautberg, Chesser, Sweeney, Kreamer and Sieverling, the
then non-employee directors, were each issued 1,039 Common Shares as a $5,000
bonus. In 1995 Mr. Chesser was issued warrants to acquire 25,000 Common Shares
at $2.50 per share, which expired December 31, 1995, for services performed for
the Company in 1991. During 1995 he exercised those warrants. See "Certain
Relationships and Related Transactions," herein.

Newly elected non-employee directors are granted a one-time restricted
stock award in Common Shares equal in value to $10,000 upon their being elected
to the Board. See "Long-Term Incentive Plan," herein.

Long-Term Incentive Plan

The Company's Long-Term Incentive Plan (the "Long-Term Incentive
Plan"), adopted in 1992, provides for the granting to certain officers and key
employees of the Company and its participating subsidiaries incentive awards in
the form of stock options, stock appreciation rights ("SARs"), Common Shares,
and cash awards. The Long-Term Incentive Plan is administered by a committee of
non-employee members of the Board of Directors with respect to awards to certain
executive officers of the Company but may be administered by the Board of
Directors with respect to any other awards (either, the "Plan Committee").
Except for certain automatic awards, the Plan Committee has discretion to select
the employees to be granted awards, to determine the type, size, and terms of
the awards, to determine when awards will be granted, and to prescribe the form
of the instruments evidencing awards.

Options, which include non-qualified stock options and incentive stock
options, are rights to purchase a specified number of Common Shares at a price
fixed at the time the option is granted. Payment may be made with cash or other
Common Shares owned by the optionee or a combination of both. Options are
exercisable at the time and on the terms that the Plan Committee determines. The
payment of the option price can be made either in cash or by the person
exercising the option turning in to the Company shares presently owned by the
person, which would be valued at the then current market price. SARs are rights
to receive a payment, in cash or Common Shares or both, based on the value of a
Common Share. A stock award is an award of Common Shares or denominated in
Common Shares that may be subject to a restriction against transfer as well as a
repurchase option exercisable by the Company. During the period of the
restriction, the employee may be given

the right to vote and receive dividends on the shares covered by restricted
stock awards. Cash awards are generally based on the extent to which
pre-established performance goals are achieved over a pre-established period but
may also include individual bonuses paid for previous, exemplary performance.

The Long-Term Incentive Plan provides for the issuance of a maximum
number of Common Shares equal to 20% of the total number of Common Shares
outstanding from time to time. Unexercised SARs, unexercised options, restricted
stock, and performance units under the Long-Term Incentive Plan are subject to
adjustment in the event of a stock dividend, stock split, recapitalization or
combination of the Company, merger, or similar transaction and are not
transferable except by will and by the laws of descent and distribution. Except
when a participant's employment terminates as a result of death, disability, or
retirement under an approved retirement plan or following a change in control in
certain circumstances, an award generally may be exercised (or the restriction
thereon may lapse) only if the participant is an officer, employee, or director
of the Company or a subsidiary at the time of exercise or lapse or, in certain
circumstances, if the exercise or lapse occurs within 180 days after employment
is terminated.

The Long-Term Incentive Plan allows for the satisfaction of a
participant's tax withholding with respect to an award by the withholding of
Common Shares issuable pursuant to the award or the delivery by the participant
of previously owned Common Shares, in either case valued at the fair market
value, subject to limitations the Plan Committee may adopt.

Awards granted pursuant to the Long-Term Incentive Plan may provide
that, upon a change of control of the Company, (a) each holder of an option will
be granted a corresponding SAR, (b) all outstanding SARs and stock options
become immediately and fully vested and exercisable in full, and (c) the
restriction period on any restricted stock award shall be accelerated and the
restriction shall expire. Options and SARs will remain exercisable for their
original terms whether or not employment is terminated following a change in
control.

The Long-Term Incentive Plan may be amended by the Board of Directors,
except that under current law no amendment that materially increases the number
of Common Shares subject to the Long-term Incentive Plan or that makes certain
other material changes may be made without shareholder approval. No grants or
awards may be made under the Long-Term Incentive Plan after the tenth
anniversary of the Closing Date. No shareholder approval will be sought for
amendments to the Long-Term Incentive Plan except as required by law (including
Rule 16b-3 under the Exchange Act) or the rules of any national securities
exchange on which the Common Shares are then listed.

There are no incentive awards pertaining to stock options, SARs or
Common Shares issued or outstanding under the Long-Term Incentive Plan.

Under the Company's Long-Term Incentive Plan beginning in 1996, all
employees on December 31 of each year share a bonus equal to 5% of the Company's
pre-tax net income, computed in accordance with GAAP, exclusive of extraordinary
and non-recurring items. The bonuses will be paid to all full time (1,000 +
hours) employees at December 31. The bonus will be paid upon delivery of the
independent audit. The bonus shall be allocated to the full time employees based
upon their salary at December 31 of that year.

Each non-employee director of the Company who becomes a director will,
on the day after the first meeting of the Board of Directors at which that
director is in attendance, automatically be granted a restricted stock award of
the number of Common Shares that have a value of $10,000, which will be
calculated based on the average trading price of the Common Shares during the 60
days immediately preceding the date of grant. These restricted stock awards will
vest over two years, with one-third vesting six months following the date of

grant, another one-third vesting on the first anniversary of the date of grant,
and the last one-third vesting on the second anniversary of the date of grant so
long as the non-employee director remains a director of the Company through
those vesting dates.

Each non-employee director will be entitled to vote each share subject
to these restricted stock awards from the date of grant until the shares are
forfeited, if ever. The Long-Term Incentive Plan requires each non-employee
director to make an election under Section 83(b) of the Code to include the
value of the restricted stock in his income in the year of grant and provides
for cash awards to the non-employee directors in amounts sufficient to pay the
federal income taxes due with respect to the award.

The following table shows information with respect to restricted stock
awards owned by non-employee directors.

Name Date of Grant Shares Price
---------- ------------- ------ -----
Michael Springs September 4, 1996 2,447 $4.09
Mark C. Barrett September 4, 1996 2,447 4.09
-----
Total 4,894

Employee Stock Ownership Plan

In 1994, the shareholders approved the adoption of the PANACO, Inc.
Employee Stock Ownership Plan ("ESOP"). The primary purposes of the ESOP are to
enable participants to acquire ownership in the Company and to provide a source
of equity capital to the Company. The ESOP establishes a trust to hold ESOP
assets, which primarily consist of Common Shares of the Company. The ESOP is
administered by the Board of Directors. Subject to the discretion of the Board
of Directors, the Company may contribute up to fifteen percent (15%) of the
participant's (including employees and other consultants to the Company) annual
compensation to the ESOP. The ESOP does not allow contributions by participants
in the Plan.

Company contributions to the ESOP may be in the form of Common Shares
or cash. Cash contributions may be used, at the discretion of the Board of
Directors, to purchase Common Shares in the open market or from the Company at
prevailing prices.

The allocation of ESOP assets is determined by a formula based on
participant compensation. Participation in the ESOP requires completion of more
than one thousand (1,000) hours of service to the Company within twelve (12)
consecutive months.

The ESOP is intended to satisfy any applicable requirements of the
Internal Revenue Code of 1986 and the Employee Retirement and Income Security
Act of 1974. The Company has been advised that its contributions to the ESOP
will be deductible for Federal Income Tax purposes, and the participants will
not recognize income on their allocated share of ESOP assets until such assets
are distributed.

As of December 31, 1996, the ESOP owned of record 84,197 Common Shares.
Such Common Shares are owned beneficially by the employees of the Company.

Beneficial Ownership Reporting Compliance

Based solely upon a review of copies of Forms 3 and 4 and amendments
thereto furnished to the Company during the fiscal year ended December 31, 1996
and Forms 5 and amendments thereto with respect to such year and certain written
representations that no Form 5 is required, the Company is not aware of any
failure on the part of any person subject to Section 16 of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), with respect to the
Company during fiscal 1996 to file on a timely basis any form or report required
by Section 16(a) of the Exchange Act during such fiscal year or prior fiscal
years.

Item 11. Executive Compensation

The following table sets forth the annual compensation paid to the
Company's Chief Executive Officer and each executive officer whose compensation
exceeds $100,000 during 1996.

Long-Term Incentive Plan
Annual Compensation Awards Payouts
Securities
Other Restricted Underlying LTIP All
Name and Principal Salary Bonus Annual Stock Options Payouts Other
Position Year ($)(1) ($) Comp. ($) Award(s) ($) (#) ($) Comp.($)(2)
- ----------------------------- ------------------------------ ------------ --------------------------------

H. James Maxwell 1996 166,900 0 0 0 0 0 22,500
President and Chief 1995 153,500 0 0 0 24,615 0 22,500
Executive Officer 1994 120,000 0 0 0 22,857 0 18,000

Larry M. Wright 1996 160,300 0 0 0 0 0 22,500
Executive Vice 1995 147,300 0 0 0 0 0 22,100
President 1994 134,000 0 0 0 0 0 20,000

Robert G. Wonish 1996 100,200 0 0 0 0 0 15,000
Vice President 1995 92,100 0 0 0 0 0 13,800
1994 78,800 0 0 0 0 0 11,800

(1) The 1993 salary figures for Messrs. Wright and Wonish include payments
made to them as independent consultants before becoming employees of the Company
in that year.
(2) The other compensation figures represent contributions to the accounts
of the employees under the Company's Employee Stock Ownership Plan. The Plan was
adopted in 1994.
Aggregated Option (Warrants) Exercises in Last Fiscal Year and Fiscal Year
End Option Values
The following table provides information relating to the number and
value of Common Shares subject to options exercised during 1996 or held by the
named executive officers as of December 31, 1996.

The following table provides information relating to the number and value
of Common Shares subject to options exercised during 1996 or held by the named
executive officers as of December 31, 1996.

Number of
securities underlying Value of unexercised
Securities unexercised options in-the-money
acquired Value at fiscal year-end ($)
options at year-end($)(2)
Name on Exercise (#) Realized ($)(1) Exercisable/Unexercisable Exercisable/Unexercisable

H. James Maxwell 0 0 -0- / -0- -0- / -0-
Larry M. Wright 0 0 250,000 / -0- 658,750 / -0-
Robert G. Wonish 0 0 -0- / -0- -0- / -0-

(1) Value realized is calculated based upon the difference between the
options exercise price and the market price of the Common Shares on the
date of exercise multiplied by the number of shares to which the
exercise price relates.
(2) Value of unexercised in-the-money options is calculated based on the
difference between the option exercise price and the closing price of
the Common Shares at year-end, multiplied by the number of shares
underlying the options. The closing price on December 31, 1996 of the
Common Shares was $4.875.

Option Grants in Last Fiscal Year

Number of Percent of
Securities total options
Underlying granted to Exercise or Market price
Options employees Base price at date Expiration Grant Date
Name Granted in fiscal year ($/Share) of grant($) Date Value($)

H. James Maxwell -0- -0- N/A N/A N/A N/A
Larry M. Wright -0- -0- N/A N/A N/A N/A
Robert G. Wonish -0- -0- N/A N/A N/A N/A

Item 12. Security Ownership of Certain Beneficial Owners and Management.

The following table sets forth information with respect to record and
beneficial ownership of Common Shares by (a) each executive officer and director
of the Company, (b) all executive officers and directors of the Company as a
group, and (c) for each person who beneficially owns 5% or more of the Common
Shares as of March 18, 1997.

Shares Owned

Name and Positions of Owners Of Record Beneficially

Number Percent Number Percent

H. James Maxwell; Chief Executive Officer,

President, Chairman of the Board & Director ............ 283,386 1.39 322,971 (1) 1.35
Larry M. Wright; Executive Vice President &
Director................................................ 395,000 1.94 654,999 (1)(2) 2.98
Bob F. Mallory; Chief Operating Officer,
Executive Vice President & Director..................... 228,030 1.12 235,496 (1) 1.07
Todd R. Bart; Chief Financial Officer &
Secretary............................................... 2,500 .01 3,997 .02
Robert G. Wonish; Vice President........................ 17,000 .08 26,410 (1) .12
William J. Doyle; Vice President ....................... - .00 6,288 (1) .03
A. Theodore Stautberg, Jr.; Director.................... 6,137 .03 9,137 .04
Donald W. Chesser; Director............................. 1,039 .01 1,039 .00
Michael Springs; Director............................... 3,096 .02 3,096 (3) .01
James B. Kreamer; Director.............................. 51,055 .25 51,055 .23
N. Lynne Sieverling; Director........................... 8,137 .04 8,137 .04
Mark C. Barrett; Director............................... 2,447 .01 2,447 (3) .01

All directors and officers as a group (13 persons)...... 997,827 4.90 1,304,302 (1) 5.90

Carl C. Icahn (4)....................................... 3,045,000 14.94 3,045,000 13.78
c/o Icahn Associates Corp.
114 West 47th Street, 19th Fl
New York, NY 10036
Richard A. Kayne (5).................................... 443,221 2.17 1,909,888 8.64
Kayne, Anderson Investment Management, Inc.
1800 Avenue of the Stars, #200
Los Angeles, CA 90067

(1) Includes shares held in the Company's Employee Stock Ownership Plan for
each officer as follows: Mr. Maxwell - 14,200 shares, Mr. Wright -14,614 shares,
Mr. Mallory - 7,466 shares, Mr. Wonish - 9,410 shares , Mr. Doyle - 6,288 shares
and Mr. Bart - 1,497 shares, and for all directors and officers as a group -
53,475 shares.
(2) Includes 250,000 shares issuable pursuant to currently exercisable
warrants.
(3) These persons were each issued 2,447 shares upon election as a director
in 1996.
(4) Mr. Icahn is the sole shareholder of Riverdale Investors Corp, Inc.,
the general partner of High River Limited Partnership, the record holder of
these shares.
(5) Includes (i) 443,221 shares held of record by Offense Group Associates,
L.P. ("Offense"), Opportunity Associates, L.P. ("Opportunity"), Kayne, Anderson
Non-Traditional Investments, L.P. ("Investments") or ARBCO Associates, L.P.
("ARBCO"), each a California limited partnership, which shares were acquired on
exercise of certain warrants issued with the 1993 Subordinated Notes; and (ii)
1,466,667 shares that are issuable upon the conversion of the 1996 Tranche A
Convertible Subordinated Notes held by Offense, Opportunity, Investments, ARBCO
or Kayne, Anderson Offshore Limited. Mr. Kayne is the President and principal
shareholder of Kayne, Anderson Investment Management, Inc., which is the general
partner of KIM Non-Traditional, L.P. ("KIM"). KIM is the general partner of
Offense, Opportunity and Investments. Mr. Kayne is the managing general partner,
and KIM is the co-general partner, of ARBCO.

Item 13. Certain Relationships and Related Transactions.

A. Theodore Stautberg, Jr., a director of the Company since 1993, is an
officer, director and beneficial shareholder of Triumph Securities Corporation,
which provided certain services in connection with the recent Common Stock
offering, and received .8% of the 6.8% Underwriters discount, namely $268,906.

During 1996 two new non-employee directors, Michael Springs and Mark C.
Barrett, were each issued restricted stock awards of 2,447 Common Shares upon
election to the Board.

Mark C. Barrett became a director of the Company on September 4, 1996.
For the years 1985 through 1995 his CPA firm, Barrett and Associates, served as
the Company's independent accountants. During 1995 his CPA firm was paid $53,400
for accounting services, including the audit.

Lenders advised by Kayne, Anderson Investment Management, Inc., in
connection with the 1993 Subordinated Notes, own 816,526 Common Shares by virtue
of their exercise of warrants issued to them in 1993

and exercised in first quarter 1996. In addition, the Company is required to pay
certain expenses, including legal fees, of those lenders.

During 1995 Donald W. Chesser, a director who is not an employee of the
Company was issued warrants to acquire 25,000 Common Shares at $2.50 per share
for past services to the Company. The warrants, which would have expired
December 31, 1995, were all exercised during 1995.

Employees of the Company are eligible to receive stock awards, stock
options, stock appreciation rights, and performance units pursuant to the
Company's Long-Term Incentive Plan.

The Company has several procedures, provisions, and plans designed to
reduce the likelihood of a change in the management or voting control of the
Company without the consent of the incumbent Board of Directors. These
provisions may have the effect of strengthening the ability of officers and
directors of the Company to continue as officers and directors of the Company
despite changes in share ownership of the Company.

Messrs. Maxwell and Mallory are the partners of 1050 Blue Ridge
Building Partnership, which owns a 5,200 square foot office building at 1050
West Blue Ridge Boulevard, Kansas City, Missouri, which they lease to the
Company on a triple net basis for $4,000 per month for a term of ten years,
expiring in 2003. The lease was approved by the Board of Directors, which
determined that the rate was as good or better than that which could be obtained
from a non-affiliated party.

H. James Maxwell and Bob F. Mallory, officers and directors of the
Company, are personal guarantors of the Company's obligation to plug the wells
and remove the platforms on the West Delta Properties acquired from Conoco, Arco
(now Vastar), Texaco and Oxy in 1991.

On October 8, 1996 the Company borrowed $17,000,000 from lenders
advised by Kayne, Anderson Investment Management, Inc. Such lenders own 443,221
Common Shares and would, upon conversion of the 1996 Tranche A Convertible
Subordinated Notes, own a total of 1,909,888 Common Shares.

Part IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

(a) See Index to Financial Statement, Page F-1.

(b) Reports on Form 8-K. The following reports on Form 8-K were
filed during the last quarter of the period covered by this
report:

October 28, 1996 Acquisition of Properties

November 18, 1996 Increase of Shares Outstanding

Exhibit
Number Description
3.1* Certificate of Incorporation of the Company.

3.2* Amendment to Certificate of Incorporation of the Company dated
November 19, 1991.

3.3* By-laws of the Company.

3.4 Amendment to Certificate of Incorporation of the Company dated
September 24, 1996 filed as an exhibit to the Amended Current Report on
Form 8-K/A, filed with the Commission on November 18, 1996, and
incorporated herein by this reference.

4.1* Article Fifth of the Certificate of Incorporation of the Company
in Exhibit 3.1.

4.2* Form of Certificate of Common Shares par value $.01 per share, of
the Company.

4.3 Rights Agreement, dated as of August 3, 1995, between PANACO,
Inc., and American Stock Transfer and Trust Company, which includes as
Exhibit A the Form of Certificate of Designation of Series A Preferred
Stock, Exhibit B the Form of Rights Certificate and Exhibit C the Summary
of Rights to Purchase Preferred Stock was filed as Exhibit 1 to the
Registration Statement on Form 8-A, filed with the Commission on August 21,
1995, and incorporated herein by this reference.

10.1* PANACO, Inc. Long-Term Incentive Plan.

10.7* Senior Second Mortgage Term Loan Agreement as of December 31,
1993, between PANACO, Inc., and seven lenders advised by Kayne Anderson
Investment Management, Inc.

10.9 Purchase and Sale Agreement, dated July 12, 1995, between Zapata
Exploration Company, Zapata Offshore Gathering Co., Inc., and PANACO, Inc.,
filed as an exhibit to the Current Report on Form 8-K filed with the
Commission on August 1, 1995, and incorporated herein by this reference.

10.11 Assignment/East Breaks 110, effective October 1, 1994, from
Zapata Exploration Company to PANACO, Inc. The Assignment/East Breaks 109
document is identical, filed as an exhibit to the Current Report on Form
8-K filed with the Commission on August 1, 1995, and incorporated herein by
this reference.

10.12 Purchase and Sale Agreement dated November 30, 1995, between
Shell Western E&P, Inc. and PANACO, Inc., filed as an exhibit to the
Current Report on Form 8-K filed, with the Commission on January 31, 1996,
and incorporated herein by this reference.

10.13***PANACO, Inc. Employee Stock Ownership Plan & Trust.

10.14 Purchase and Sale Agreement, dated August 26, 1996, between
Amoco Production Company and PANACO, Inc., filed as an exhibit to the
Current Report on Form 8-K, filed with the Commission on October 28, 1996,
and incorporated herein by this reference.

10.15 Amended and Restated Credit Agreement, dated October 7, 1996,
among First Union National Bank of North Carolina, as agent, and the
lenders signatory thereto, and PANACO, Inc., filed as an exhibit to the
Amended Current Report on Form 8-K/A, filed with the Commission on November
18, 1996, and incorporated herein by this reference.

10.16 Senior Subordinated Mortgage Master Loan Agreement dated October
8, 1996 between PANACO, Inc. and Offense Group Associates, L.P., Kayne,
Anderson Non-Traditional Investments, L.P., ARBCO Associates, L.P.,
Opportunity Associates, L.P., Kayne, Anderson Offshore Limited, Foremost
Insurance Company, TOPA Insurance Company and EOS Partners, L.P. and
Offense, as agent for the Lenders, filed as an exhibit to the Amended
Current Report on Form 8-K/A, filed with the Commission on November 18,
1996, and incorporated herein by this reference.

10.17 Purchase and Sale Agreement, dated November 11, 1996 between
National Energy Group, Inc. and PANACO, Inc., filed as an exhibit to the
Current Report on Form 8-K filed with the Commission on January 29, 1997,
and incorporated herein by this reference.

27 Financial Data Schedule.

*Filed with the Registration Statement on Form S-4, Commission File
No. 33-44486, initially filed December 13, 1991, and incorporated herein by
this reference.

** Filed with the Registration Statement on Form S-1, Commission file
No. 33-81058, initially filed July 1, 1994, and incorporated herein by this
reference.

***Filed with the Registration Statement on Form S-1, Commission file
No. 333-18233, initially filed December 19, 1996 and incorporated herein by
this reference.

(d) Financial Statement Schedules. See Index to Financial Statements,
Page F-1.

SIGNATURES

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

PANACO, Inc.

By: \s\H. James Maxwell
H. James Maxwell, President

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

By: \s\ H. James Maxwell
H. James Maxwell, President
Chief Executive Officer and
Director

By: \s\Bob F. Mallory
Bob F. Mallory, Executive
Vice President, Chief Operating
Officer and Director

By: \s\Todd R. Bart
Todd R. Bart, Chief Financial
Officer, Treasurer and Secretary

By: \s\N. Lynn Sieverling
N. Lynn Sieverling, Director

By: \s\Larry M. Wright
Larry M. Wright, Executive
Vice President and Director

By: \s\A. Theodore Stautberg
A. Theodore Stautberg, Director

PANACO, INC.
INDEX TO FINANCIAL STATEMENTS

Page

PANACO, INC. - AUDITED FINANCIAL STATEMENTS

Independent Auditors' Report F-2
Independent Auditors' Report F-3
Balance Sheets, December 31, 1996 and 1995 F-4
Statements of Income (Operations) for the Years Ended
December 31, 1996, 1995 and 1994 F-6
Statements of Changes in Stockholders' Equity
for the Years Ended December 31, 1996, 1995 and 1994 F-7
Statements of Cash Flows for the Years Ended
December 31, 1996, 1995 and 1994 F-8
Notes to Financial Statements for the Years Ended
December 31, 1996, 1995 and 1994 F-10
AMOCO PROPERTIES

Independent Auditors' Report F-21
Statement of Revenues and Direct Operating Expenses F-22
Notes to the Statement F-23

F-1

Report of Independent Public Accountants

To the Board of Directors
PANACO, Inc.

We have audited the accompanying balance sheet of PANACO, Inc. (a
Delaware Corporation) as of December 31, 1996, and the related statements of
income (operations), changes in 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. The financial statements of PANACO, Inc. for the
years ended December 31, 1995 and 1994 were audited by other auditors whose
report dated February 26, 1996 (except with respect to the change in accounting
for oil and gas properties, as to which the date is June 7, 1996), expressed an
unqualified opinion on those statements and included an explanatory paragraph
that described the retroactive change in accounting for oil and gas properties.

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 1996 financial statements referred to above present
fairly, in all material respects, the financial position of PANACO, Inc. as of
December 31, 1996, and the results of its operations and its cash flows for the
year then ended in conformity with generally accepted accounting principles.

Arthur Andersen LLP

Kansas City, Missouri
March 7, 1997

F-1

Independent Auditors' Report

To the Board of Directors
PANACO, Inc.

We have audited the accompanying balance sheets of PANACO, Inc. (a Delaware
corporation) as of December 31, 1995 and the related statements of income
(operations), changes in Stockholders' equity and cash flows for each of the two
years in the period ended December 31, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the Financial Statements, the Company has given
retroactive effect to the change in accounting for its oil and gas operations.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PANACO, Inc. as of December 31,
1995 and the results of its operations, changes in stockholders' equity and cash
flows for each of the two years in the period ended December 31, 1995 in
conformity with generally accepted accounting principles.

BARRETT & ASSOCIATES
Overland Park, Kansas

February 26, 1996, except for Note 1, which the date is June 7, 1996.

F-2

PANACO, INC.
BALANCE SHEETS

ASSETS

December 31,
1996 1995

CURRENT ASSETS

Cash and cash equivalents $ 1,736,000 $ 1,198,000
Accounts receivable 6,197,000 4,386,000
Investment in common stock 1,642,000 ---
Prepaid and other 424,000 465,000
------------- --------------
Total current assets 9,999,000 6,049,000
------------- --------------

OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
Oil and gas properties, proved 125,283,000 103,105,000
Oil and gas properties, unproved 7,128,000 ---
Less accumulated depreciation, depletion, amortization,
and valuation allowances (81,871,000) (73,620,000)
----------- -----------
Net oil and gas properties 50,540,000 29,485,000
------------ ------------

PROPERTY, PLANT, AND EQUIPMENT
Pipelines and equipment 10,534,000 196,000
Less accumulated depreciation (327,000) (92,000)
-------------- --------------
Net property, plant, and equipment 10,207,000 104,000
-------------- --------------

OTHER ASSET
Restricted deposits 2,115,000 ---
Loan costs, net 611,000 471,000
Other 296,000 60,000
--------------- --------------
Total other assets 3,022,000 531,000
--------------- --------------

TOTAL ASSETS $ 73,768,000 $36,169,000
================ ===========

The accompanying notes are an integral part of this
statement.

F-3

LIABILITIES AND STOCKHOLDERS' EQUITY

December 31,
1996 1995

CURRENT LIABILITIES

Accounts payable $ 6,246,000 $ 4,444,000
Interest payable 524,000 161,000
Current portion of long-term debt --- ---
------------- -------------
Total current liabilities 6,770,000 4,605,000
------------- -------------

LONG-TERM DEBT 49,500,000 22,390,000

STOCKHOLDERS' EQUITY

Preferred Shares, $.01 par value,
1,000,000 shares authorized; no
shares issued and outstanding --- ---
Common Shares, $.01 par value,
40,000,000 shares authorized;
14,350,255 and 11,504,615 shares
issued and outstanding, respectively 143,000 115,000
Additional paid in capital 31,490,000 21,155,000
Retained earnings (deficit) (14,135,000) (12,096,000)
------------ ------------
Total Stockholders' Equity 17,498,000 9,174,000
------------ -------------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 73,768,000 $ 36,169,000
============= ============

The accompanying notes are an integral part of this
statement.

F-4

PANACO, INC.
STATEMENTS OF INCOME (OPERATIONS)

Year Ended December 31,
1996 1995 1994
REVENUES

Oil and gas sales $20,063,000 $18,447,000 $ 17,338,000

COSTS AND EXPENSES
Lease operating 8,477,000 8,055,000 5,231,000
Depreciation, depletion and amortization 9,022,000 8,064,000 6,038,000
General and administrative 772,000 690,000 587,000
Production and ad valorem taxes 559,000 1,078,000 1,006,000
Exploration expenses --- 8,112,000 ---
Provision for losses and (gains) on disposition
and write-down of assets --- 751,000 1,202,000
West Delta fire loss 500,000 --- ---
----------- ------------ -----------
Total 19,330,000 26,750,000 14,064,000
----------- ------------ -----------

NET OPERATING INCOME (LOSS) 733,000 (8,303,000) 3,274,000
----------- ------------ -----------

OTHER INCOME (EXPENSE)
Unrealized loss on investment in common stock (258,000) --- ---
Interest expense, net (2,514,000) (987,000) (1,623,000)
----------- ------------ -----------
Total (2,772,000) (987,000) (1,623,000)
----------- ------------ -----------
NET INCOME (LOSS) BEFORE INCOME
TAXES AND EXTRAORDINARY ITEM (2,039,000) (9,290,000) 1,651,000
INCOME TAXES --- --- ---
----------- ------------ -----------
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM (2,039,000) (9,290,000) 1,651,000
EXTRAORDINARY ITEM - LOSS ON EARLY
RETIREMENT OF DEBT --- --- (536,000)
------------ ------------ -----------
NET INCOME (LOSS) $ (2,039,000) $ ( 9,290,000) $ 1,115,000
============ ============== =============

EARNINGS (LOSS) PER COMMON SHARE
Earnings (loss) before extraordinary item (.16) (.81) .16
Extraordinary loss --- --- (.05)
------------- ------------ ------------
Net earnings (loss) $ (.16) $ (.81) $ .11
============= ============ =============

Weighted average shares outstanding: 12,742,213 11,504,615 9,952,870
============ ============ =============

The accompanying notes are an integral part of this
statement.

F-5

PANACO, INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996

Common Additional Retained
Share Paid-In Earnings
Shares Par Value Capital (Deficit)

Balances, December 31, 1993 8,155,255 $ 82,000 $12,583,000 $(3,921,000)

Net Income --- --- --- 1,115,000
Exercises of stock options and warrants and
shares issued under Employee Stock
Ownership Plan 2,064,883 20,000 5,003,000 ---
---------- ----------- ------------ ------------
Balances, December 31, 1994 10,220,138 102,000 17,586,000 (2,806,000)

Net Loss --- --- --- (9,290,000)
Exercise of stock options and warrants 1,181,602 12,000 3,137,000 ---
Issuance of new shares 102,875 1,000 432,000 ---
----------- ------------ ------------ -------------
Balances, December 31, 1995 11,504,615 115,000 21,155,000 (12,096,000)

Net Loss --- --- --- (2,039,000)
Exercise of warrants, shares issued under
Employee Stock Ownership Plan and
Director stock bonuses 845,640 8,000 1,955,000 ---
Acquisition of properties 2,000,000 20,000 8,380,000 ---
----------- ---------- ------------ -------------
Balances, December 31, 1996 14,350,255 $ 143,000 $31,490,000 $(14,135,000)
============ ========= =========== =============

The accompanying notes are an integral part of this
statement.

F-6

PANACO, INC.
STATEMENTS OF CASH FLOWS
Year Ended December 31,
1996 1995 1994
CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss) before extraordinary item $(2,039,000) $(9,290,000) $ 1,651,000
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation, depletion, and amortization 9,022,000 8,065,000 6,378,000
Exploration expenses --- 8,112,000 ---
Provision for losses and (gains) on disposition
and write-down of assets --- 751,000 1,202,000
Unrealized loss on investment in common stock 258,000 --- ---
ESOP stock contribution 122,000 132,000 123,000
Changes in operating assets and liabilities:
Accounts receivable (1,811,000) (2,155,000) (1,202,000)
Prepaid and other 274,000 (125,000) (501,000)
Accounts payable 1,803,000 2,916,000 (202,000)
Interest payable 363,000 (24,000) 26,000
Extraordinary loss --- --- (536,000)
-------------- -------------- --------------
Net cash provided by operating activities 7,992,000 8,382,000 6,939,000
-------------- -------------- --------------

CASH FLOWS FROM INVESTING ACTIVITIES
Sale of oil and gas properties 9,017,000 11,000 300,000
Capital expenditures and acquisitions (42,958,000) (21,803,000) (12,101,000)
Purchase of other property and equipment, net (92,000) (38,000) (27,000)
Increase in restricted deposits (2,115,000) --- ---
Other 96,000 --- ---
-------------- ------------- --------------
Net cash used by investing activities (36,052,000) (21,830,000) (11,828,000)
-------------- ------------ --------------

CASH FLOW FROM FINANCING ACTIVITIES
Long-term debt proceeds 38,863,000 16,890,000 5,564,000
Repayment of long-term debt (11,753,000) (7,000,000) (7,326,000)
Issuance of common shares - exercise of
warrants and options 1,837,000 3,173,000 5,023,000
Additional loan costs ( 349,000) --- ---
------------- ------------- -------------
Net cash provided by financing activities 28,598,000 13,063,000 3,261,000
------------- ------------- -------------

NET INCREASE (DECREASE) IN CASH 538,000 (385,000) (1,628,000)

CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 1,198,000 1,583,000 3,211,000
------------- ------------ -------------

CASH AND CASH EQUIVALENTS AT END OF YEAR $ 1,736,000 $ 1,198,000 $ 1,583,000
============ ============ ===========

The accompanying notes are an integral part of this
statement.

F-8

Supplemental schedule of non-cash investing and financing activities:

FOR THE YEAR ENDED DECEMBER 31, 1996:

The Company issued 2,000,000 shares of common stock totaling $8,400,000 to Amoco
Production Company in connection with an acquisition of oil and gas assets.

The Company issued 2,447 shares of common stock each to two new directors. The
Company also issued 24,220 shares to the ESOP.

The Company received 477,612 shares of National Energy Group, Inc. common stock
in connection with the sale of the Bayou Sorrel Field.

FOR THE YEAR ENDED DECEMBER 31, 1995:

The Company issued 97,680 shares of common stock totaling $409,000 in exchange
for oil and gas properties.

FOR THE YEAR ENDED DECEMBER 31, 1994:

The Company farmed out an oil and gas property and retained a 12.5% overriding
royalty interest.

The Company contributed 30,850 shares to the ESOP.

Supplemental disclosures of cash flow information:

Cash paid during the year ended December 31:

1996 1995 1994
---- ---- ----

Interest $2,218,000 $1,016,000 $1,409,000
========== ========== ==========

Income taxes $ --- $ --- $ ---
========== =========== ==========

F-9

PANACO, INC.

NOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 1996, 1995, AND 1994

Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of PANACO, Inc. (the Company) is
presented to assist in understanding the Company's financial statements. The
financial statements and notes are representations of the Company's management,
who are responsible for the integrity and objectivity of the financial
statements. These accounting policies conform to generally accepted accounting
principles and have been consistently applied in the preparation of the
financial statements.

Revenue Recognition
The Company recognizes its ownership interest in oil and gas sales as revenue.
It records revenues on an accrual basis, estimating volumes and prices for any
months for which actual information is not available. If actual production sold
differs from its allocable share of production in a given period, such
differences would be recognized as deferred income or accounts receivable.

Hedging Transactions
The Company hedges the prices of its oil and gas production through the use of
oil and natural gas futures and swap contracts within the normal course of its
business. The Company uses futures and swap contracts to reduce the effects of
fluctuations in oil and natural gas prices. Changes in the market value of these
contracts are deferred and subsequent gains and losses are recognized monthly as
adjustments to revenues in the same production period as the hedged item, based
on the difference between the index price and the contract price. The Company
entered into a hedge agreement beginning in January, 1996, for the delivery of
15,000 MMBTU of gas for each day in 1996 with contract prices ranging from
$1.7511/MMBTU to $2.253/MMBTU.

Starting in 1997 the Company's hedge transactions on natural gas are based upon
published gas pipeline index prices and not the NYMEX. This change has
eliminated price differences due to transportation. For 1997, 14,000 MMBTU's per
day has been hedged, reduced to 10,000 MMBTU's per day in 1998 and 7,000 MMBTU's
per day in 1999. The Company is hedging at a swap price of $1.80/MMBTU for 1997,
with varying levels of participation (93% in January to 66% in December) in
settlement prices above $1.80/MMBTU.

Starting in 1997, the Company has also hedged 720 barrels of oil for each day in
1997 at a swap price of $20.00 per barrel. The Company then has a 40%
participation in settlement prices above the swap price.

Income Taxes
The Company records income taxes in accordance with the requirements of
Statement of Financial Accounting Standards (FAS) No. 109 - "Accounting for
Income Taxes", which requires recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been included in
the financial statements or tax returns. Under this method, deferred tax assets
and liabilities are determined based on the differences between the financial
statement and tax bases of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse.

F-10

Oil and Gas Producing Activities and Depreciation, Depletion and Amortization
The Company utilizes the successful efforts method of accounting for its oil and
gas properties. Under the successful efforts method, lease acquisition costs are
capitalized. Exploratory drilling costs are also capitalized pending
determination of proved reserves. If proved reserves are not discovered, the
exploratory costs are expensed. All development costs are capitalized. Provision
for depreciation and depletion is determined on a field-by-field basis using the
unit-of-production method. The carrying amounts of unproved properties are not
depleted until a determination of any reserves has been made. The carrying
amounts of proven and unproven properties are reviewed periodically on a
property-by-property basis, based on future net cash flows determined by an
independent engineering firm, and an impairment reserve is provided as
conditions warrant. The provision for write down of assets were $751,000 for
1995, and $1,202,000 for 1994.

Property, Plant & Equipment
Property and equipment are carried at cost. Oil and natural gas pipelines and
equipment are depreciated on the straight-line method over estimated remaining
useful lives, primarily fifteen years. Other property is also depreciated on the
straight-line method over estimated remaining useful lives, ranging from five to
seven years.

Amortization of Note Discount
Note discounts are amortized utilizing the interest method, which applies a
constant rate of interest to the book value of the note. Additional interest
expense of $234,000 was recorded in 1994 from the amortization of the discount.
Effective July 1, 1994 the debt related to the note discount was extinguished,
and the balance of the note discount totaling $106,000 was recorded as an
extraordinary item.

Earnings (Loss) per share
The computation of earnings or loss per share in each year is based on the
weighted average number of common shares outstanding. When dilutive, stock
options and warrants are included as share equivalents using the treasury share
method. Stock options and warrants were not included in the calculation for 1995
and 1996, as the effects were not dilutive. Shares to be contributed to the ESOP
plan are treated as common share equivalents.

Statement of Cash Flows
For purposes of reporting cash flows, the Company considers all cash investments
with original maturities of three months or less to be cash equivalents.

Use of Estimates
The preparation of financial statements in accordance with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses and
disclosure of contingent assets and liabilities in the financial statements,
including the use of estimates for oil and gas reserve information and the
valuation allowance for deferred income taxes. Actual results could differ from
those estimates. Estimates related to oil and gas reserve information and the
standardized measure are based on estimates provided by third parties. Changes
in prices could significantly affect these estimates from year to year.

Reclassification
Certain financial statement items have been reclassified to conform to the
current year's presentation.

Note 2 - ACQUISITIONS & DISPOSITIONS

On October 8,1996, the Company closed its acquisition of interests in thirteen
offshore blocks comprising six fields in the Gulf of Mexico from Amoco
Production Company ("Amoco Properties"). The purchase price for the assets
acquired in this transaction was $40.4 million, paid by the issuance of
2,000,000 Common Shares,

F-11

valued at $4.20 per share, and by payment to Amoco of $32 million in cash. Based
on the assets acquired, the Company allocated $25,737,000 of the purchase price
to proved oil and gas properties, $9,273,000 to pipelines and structures and
$5,390,000 to unproved oil and gas properties. Concurrently with this
transaction the Company entered into a new Bank Facility with First Union
National Bank of North Carolina and Banque Paribas under which its reducing
revolving loan was increased to $40 million, with an initial borrowing base
(credit limit) of $35 million. In addition to that facility, the Company
borrowed $17 million pursuant to the Tranche A Convertible and the Tranche B
Bridge Loan Subordinated Notes (see Note 6).

On July 12, 1995, the Company entered into a Purchase and Sale Agreement with
Zapata Exploration Company to acquire all of Zapata's offshore oil and gas
properties in the Gulf of Mexico ("Zapata Properties"). The transaction closed
July 26, 1995. The purchase price for the assets acquired in this transaction
was $2,748,000 in cash and the obligation to pay a production payment to Zapata
based upon future production. The production payment is based upon production
from the East Breaks 109 field after production of 12 Bcfe gross (10 Bcfe net)
measured from October 1, 1994. The Company will pay to Zapata $.4167 per Mcfe on
the next 27 Bcfe produced. Payments to Zapata on this production payment are to
be made by the Company when it is paid for the oil or gas. Oil and gas reserves
attributable to this production payment are not included in the reserves for the
properties set forth herein.

Both of these acquisitions were accounted for using the purchase method. The
results for the Amoco Properties are included in the Company's results of
operations from October 8 to December 31, 1996. The results for the Zapata
Properties are included in the Company's results of operations from July 26 to
December 31, 1995 and all of 1996.

Effective September 1, 1996, the Company sold its Bayou Sorrel Field to National
Energy Group, Inc. for $11,000,000, consisting of $9,000,000 in cash and 477,612
shares of National Energy Group, Inc. common stock. This field was purchased by
the Company on December 27, 1995 from Shell Western E & P, Inc. for $10,500,000,
which included a $204,000 broker's fee and a related receivable of $600,000. The
Company retained a 3% overriding royalty interest in the deep rights of the
field, below 11,000 feet. There was no gain or loss on the sale of the field and
the $1,738,000 remaining net book valve was assigned to this overriding royalty
interest.

The following unaudited pro forma financial information assumes the Amoco and
Zapata acquisitions had been consummated January 1, 1995, and the Bayou Sorrel
sale was completed January 1, 1996. It is presented in order to comply with the
disclosure requirements of Accounting Principles Board Opinion No. 16. The pro
forma financial information does not purport to be indicative of the results of
the Company had these acquisitions occurred on the date assumed, nor is it
necessarily indicative of the future results of the Company. It should be read
together with the financial statements of the Company, including the notes
thereto.

F-12

PANACO, Inc.
Unaudited Pro Forma Financial Information
For the Years Ended December 31, 1996 and 1995

1996 1995
---- ----
Unaudited Unaudited
PANACO, Inc. PANACO, Inc.
Pro Forma Pro Forma
Combined Combined

Revenues $ 28,978,000 $ 34,598,000

Income/(loss) before extraordinary items (1,928,000) (13,213,000)

Net Income/(loss) (1,928,000) (13,213,000)

Earnings/(loss) per share $ (0.13) $ (0.98)

Note 3 - WEST DELTA FIRE LOSS

The Company experienced an explosion and fire on April 24, 1996 at Tank Battery
#3 in West Delta resulting in the fields being shut-in from April 24th, until
being returned to production on October 7, 1996. The loss of 67 days of
production in the second quarter and the entire third quarter resulted in lost
revenues of approximately $6,000,000. The fire was the principal contributor to
the losses of $.08 per share for the second quarter of 1996 and $.11 per share
for the third quarter. During the second quarter the Company expensed $500,000
for its loss as a result of this explosion. No further losses have been
recognized or are anticipated. This $500,000 amount included $225,000 in
deductibles under the Company's insurance.

Note 4 - INVESTMENT IN COMMON STOCK

In connection with a sale of the Bayou Sorrel to National Energy Group, Inc.,
the Company received 477,612 shares of National Energy Group, Inc. common stock.
The market value was $1,900,000 based upon the trading price of the stock on the
NASDAQ National Market.

The Company has classified this investment as a trading security. At December
31, 1996 the market value of the Company's investment in National Energy Group,
Inc. was $1,642,000, with a $258,000 valuation allowance being recognized to
reflect the decrease in market value of the common stock.

Note 5 - RESTRICTED DEPOSITS

Pursuant to existing agreements the Company is required to deposit funds in bank
escrow and trust accounts to provide a reserve against satisfaction of its
eventual responsibility to plug and abandon wells and remove structures when
certain fields no longer produce oil and gas. Each month, until November 1997,
$25,000 is deposited in a bank escrow account, to satisfy such obligations with
respect to a portion of its West Delta

F-13

Properties. The Company has entered into an escrow agreement with Amoco
Production Company under which the Company will deposit, for the life of the
fields, ten percent (10%) of the net cash flow, as defined in the agreement,
from the Amoco properties. As of December 31, 1996 the Company has established
the "PANACO East Breaks 110 Platform Trust" in favor of the Minerals Management
Service of the U.S. Department of the Interior. This trust requires an initial
funding of $846,720 in December 1996, and remaining deposits of $244,320 due at
the end of each quarter in 1999 and $144,000 due at the end of each quarter in
2000, for a total of $2,400,000. In addition, the Company has $9,250,000 in
surety bonds to secure its plugging and abandonment obligations; including a
$4,100,000 bond which was provided to the original sellers of the West Delta
Properties; a $2,400,000 supplemental bond provided to the Minerals Management
Service of the U.S. Department of the Interior in connection with the plugging
and structure removal obligations for the Company's East Breaks Block 110
Platform and a $300,000 Pipeline Right-of-Way Bond.

Note 6- LONG-TERM DEBT
1996 1995
------------- ------------
Note payable (a) $ 27,500,000 $ 17,390,000
Note payable (b) 22,000,000 5,000,000
------------- -------------
49,500,000 22,390,000

Less current portion --- ---
------------- -------------
Long-term debt $ 49,500,000 $ 22,390,000
============= ============

(a) On October 8, 1996, the Company amended its bank facility with First
Union National Bank of North Carolina (60% participation), and Banque
Paribas (40% participation), herein "Bank Facility". The loan is a
reducing revolver designed to provide the Company up to $40 million
depending on the Company's borrowing base, as determined by the
lenders. The Company's borrowing base at December 31, 1996 was $31
million, with an availability under the revolver of $2.5 million. The
principal amount of the loan is due July 1, 1999. However, at no time
may the Company have outstanding borrowings under the Bank Facility in
excess of its borrowing base. Interest on the loan is computed at the
bank's prime rate or at 1 to 1 3/4% (depending upon the percentage of
the facility being used) over the applicable London Interbank Offered
Rate ("LIBOR") on Eurodollar loans. Eurodollar loans can be for terms
of one, two, three or six months and interest on such loans is due at
the expiration of the terms of such loans, but no less frequently than
every three months. The Company's weighted average interest rate at
December 31, 1996 was 7.29%. The bank facility is collateralized by a
first mortgage on the Company's offshore properties. The loan
agreement contains certain covenants including a requirement to
maintain a positive indebtedness to cash flow ratio, a positive
working capital ratio, a certain tangible net worth, as well as
limitations on future debt, guarantees, liens, dividends, mergers,
material change in ownership by management, and sale of assets.

(b) From time to time the Company has borrowed funds from institutional
lenders who are advised by Kayne, Anderson Investment Management, Inc.
In each case these loans are due at a stated maturity, require
payments of interest only at 12% per annum 45 days after the end of
each calendar quarter and are secured by a second mortgage on the
Company's offshore oil and gas properties. The respective loan
documents contain certain covenants including a requirement to
maintain a net worth ratio, as well as limitations on future debt,
guarantees, liens, dividends, mergers, material change in ownership by
management, and sale of assets. The loans are as follows:

(I) 1993 Subordinated Notes. In 1993, $5,000,000 was borrowed, due
December 31, 1999, but prepayable at any time. The Company could have
delivered up to $1,000,000 in PIK (payment in kind) notes in satisfaction
of interest payment obligations. The lenders were issued, and during 1996
exercised, warrants to acquire 816,526 Common Shares at $2.25 per share. In
March, 1997 the Company repaid these notes.

F-14

(ii) 1996 Tranche A Convertible Subordinated Notes. On October 8,
1996, $8,500,000 was borrowed, due October 8, 2003, but prepayable any
time after May 8, 1998. The Notes are, after August 28, 1997, convertible,
into 2,060,606 common shares on the basis of $4.125 per share. The Company
may deliver up to $2,000,000 in PIK notes in satisfaction of interest
payment obligations.

(iii) 1996 Tranche B Bridge Loan Subordinated Notes. On October 8,
1996, $8,500,000 was borrowed, due October 8, 2003, but prepayable at any
time. In March, 1997 the Company repaid these notes.

Maturities of long-term debt are as follows:

July 1, 1999 $27,500,000
December 31, 1999 5,000,000
October 8, 2003 17,000,000
------------
$49,500,000

Note 7 - STOCKHOLDERS' EQUITY

During 1996, 816,526 shares were issued by virtue of the exercise of warrants at
an exercise price of $2.25 per share, 24,220 shares were contributed to the
Company's ESOP and 4,894 were issued for board of director fees. On October 8,
1996, 2,000,000 shares were issued to Amoco Production Company in connection
with an acquisition of oil and gas assets. During 1995, 1,181,602 shares were
issued by virtue of the exercise of warrants and options, 97,680 shares were
issued in connection with property acquisition costs and 5,195 shares were
issued for board of directors fees. During 1994, 2,034,033 shares were issued by
virtue of the exercise of warrants and options, and 30,850 shares were
contributed to the Company's ESOP.

In August, 1994, the Company established an Employee Stock Ownership Plan (ESOP)
and Trust that covers substantially all employees. The Board of Directors can
approve contributions, up to a maximum of 15% of eligible employees' gross
wages. The Company incurred $ 122,000, $132,000 and $123,000 in costs for the
years ended December 31, 1996, 1995 and 1994, respectively.

Warrants outstanding at December 31, 1996 to acquire common shares are as
follows:

Number of Price per
Shares Share Expiration Date
-------- ---------- ------------------
90,000 $2.000 July 31, 1997
160,000 $2.375 December 31, 1997
39,365 $2.000 December 31, 1997
---------
289,365

The 1996 Tranche A Convertible Subordinated Notes are, after August 28, 1997,
convertible into 2,060,606 common shares on the basis of $4.125 share.

On August 26, 1992, the shareholders approved a long-term incentive plan
allowing the Company to grant incentive and nonstatutory stock options,
performance units, restricted stock awards and stock appreciation rights to key
employees, directors, and certain consultants and advisors of the Company up to
a maximum of 20% of the total number of shares outstanding. At December 31, 1996
or 1995, there were no stock options outstanding.

F-15

During 1995, under the terms of the Long-Term Incentive Plan, three directors
surrendered 73,845 shares to exercise 124,400 options. New options were issued
equal to the number of shares surrendered at a price of $2.0313 per share, which
would have expired December 31, 1995, but were exercised by that date.

Note 8 - RELATED PARTY TRANSACTIONS

During 1995, 25,000 warrants at a price of $2.50 per share were issued to and
exercised by a director. During 1994, 650,000 warrants at a price of $2.75 per
share were issued to the directors. All such warrants were exercised during
1994.

The Company entered into a triple net lease agreement with a partnership owned
by two directors for the lease of an office building. The lease, which expires
November, 2003, has monthly rental payments of $4,000. During 1996, 1995 and
1994, $48,000 per year in rent was paid under the lease agreement.

The following is a schedule of future rental payments required under this
office building lease:

Year ending December 31,

1997 $ 48,000
1998 48,000
1999 48,000
2000 48,000
2001 48,000
2002-2003 92,000
$ 332,000

In 1994, 275,000 options were issued to directors at prices ranging from $2.32
to $3.94 per share. These options were exercised in 1995. Under the terms of the
Long-Term Incentive Plan, three directors were issued 73,845 options at $2.03
per share and 68,567 options at $2.19 per share in 1995 and 1994, respectively.
These options were exercised in 1995.

Note 9 - INCOME TAXES

At December 31, 1996, the Company had net operating loss carry forwards for
federal income tax purposes of $16,000,000 which are available to offset future
federal taxable income through 2011. The Company's timing of its utilization of
net operating loss carry forwards may be limited in the future due to its
issuance of common stock and the related I.R.S. regulations.

F-16

Significant components of the Company's deferred tax assets as of December 31
are as follows:

1996 1995
------------ ----------
Deferred tax assets

Fixed asset basis differences $ 2,312,000 $ 1,408,000
Net operating loss carry forwards 6,342,000 6,306,000
----------- ------------
Total deferred tax assets 8,654,000 7,714,000
---------- ------------

Valuation allowance for deferred
tax assets (8,654,000) (7,714,000)
------------ -----------
Total deferred tax assets $ --- $ ---
============ =============

A valuation allowance is provided to reduce the deferred tax assets to a level
which, more likely than not, will be realized. The valuation allowance for
deferred tax assets as of December 31, 1994 was $4,061,000. The net change in
the total valuation allowance for the years ended December 31, 1996 and 1995 was
an increase of $940,000 and $3,653,000, respectively.

Note 10 - COMMITMENTS AND CONTINGENCIES

The Company is subject to various legal proceedings and claims which arise in
the ordinary course of business operations. In the opinion of management, the
amount of liability, if any, with the respect to these actions would not
materially affect the financial position of the Company or its results of
operation.

Note 11 - FINANCIAL INSTRUMENTS

The carrying amount and fair values of the Company's financial instruments at
December 31, 1996, are as follows:

Assets (Liabilities)
--------------------------------------
Carrying Amount Fair Value
Long-term fixed rate debt $ (22,000,000) $ (21,063,000)
Off balance sheet financial instruments
Letter of credit - ---
Hedge contracts - (897,000)

Cash and cash equivalents, receivables, payables, and long-term variable rate
debt The carrying amount reported on the consolidated balance sheet approximates
its fair value because of the short maturities of these instruments.

Long-term, fixed rate debt
The Company estimates the fair value of its long-term, fixed rate debt generally
using discounted cash flow analysis based on the Corporation's current borrowing
rates for debt with similar maturities.

Letter of credit
A $1,000,000 letter of credit collateralizes a plugging bond. Fair value
estimated on the basis of fees paid to obtain the obligation is not material at
December 31, 1996.

F-17

Hedge contracts
The fair values of the Company's swap contracts are estimated based on
settlement values at December 31, 1996 for volumes hedged at future dates.

Concentrations of Credit Risk
Financial instruments which potentially subject the Company to concentration of
credit risk consist principally of bank account balances in excess of federally
insured limits and trade receivables. The Company's receivables consist of oil
and gas sales to third parties primarily from offshore production in the Gulf of
Mexico and onshore oil production in the central part of the United States. This
concentration may impact the Company's overall credit risk, either positively or
negatively, in that these entities may be similarly affected by changes in
economic or other conditions. Receivables are generally not collateralized.
Historical credit losses incurred by the Company on receivables have not been
significant. One purchaser accounted for 49%, 69% and 83% of revenues in 1996,
1995 and 1994, respectively.

NOTE 12 - SUBSEQUENT EVENTS

On March 5, 1997, the Company completed an offering of 8,403,305 shares of
common stock at $4.00 per share, $3.728 net of the underwriter's commission,
consisting of 6,000,000 shares sold by the Company and 2,403,305 shares sold by
shareholders, primarily 2,000,000 by Amoco Production Company which were
received in connection with a property acquisition and 373,305 by lenders
advised by Kayne, Anderson Investment Management, Inc which were received in
connection with the exercise of warrants. The Company's proceeds of $22,000,000
(net of $350,000 in offering expenses) from the offering were used to repay
$13,500,000 of its Subordinated Notes, specifically the 1993 Subordinated Notes
and the 1996 Tranche B Bridge Loan Subordinated Notes. The remaining proceeds
were temporarily paid on the Company's reducing revolving loan and will
ultimately be used for the development of its properties and future
acquisitions. These payments, along with payments made from the Company's cash
flows reduced its Long-Term debt balance at $24,000,000 on March 6, 1997.

Note 13 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)

The following table reflects the costs incurred in oil and gas property
activities for each of the three years ended December 31:

1996 1995 1994
------------- ------------- --------------

Property acquisition costs, proved $ 26,859,000 $ 12,603,000 $ 352,000

Property acquisition costs, unproved 5,390,000 ---

Exploration costs 8,112,000 ---

Development costs 8,863,000 1,497,000 11,749,000

Quantities of Oil and Gas Reserves

The estimates of proved developed and proved undeveloped reserve quantities at
December 31, 1996 are based upon reports of third party petroleum engineers
(Ryder Scott Company and McCune Engineering, P.E.) and do

F-18

not purport to reflect realizable values or fair market values of PANACO's
reserves. It should be emphasized that reserve estimates are inherently
imprecise and accordingly, these estimates are expected to change as future
information becomes available. These are estimates only and should not be
construed as exact amounts. All reserves are located in the United States.

Proved reserves are estimated reserves of natural gas and crude oil and
condensate that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those expected
to be recovered through existing wells, equipment, and operating methods.

Proved developed and undeveloped reserves:
Oil Gas
(BBLS) (MCF)

Estimated reserves as of December 31, 1993 745,000 43,696,000

Production (137,000) (8,139,000)
Extensions and discoveries 183,000 16,930,000
Sale of minerals in-place (24,000) (45,000)
Revisions of previous estimates 176,000 (10,860,000)
--------------- -----------
Estimated reserves as of December 31, 1994 943,000 41,582,000

Production (170,000) (9,850,000)
Sale of minerals in-place (1,000) (22,000)
Purchase of minerals in-place 1,140,000 20,094,000
Revisions of previous estimates (12,000) (5,093,000)
--------------- -----------
Estimated reserves as of December 31, 1995 1,900,000 46,711,000

Production (276,000) (6,788,000)
Extensions and discoveries --- 972,000
Sale of minerals in-place (805,000) (3,102,000)
Purchase of minerals in-place 1,379,000 16,633,000
Revisions of previous estimates 41,000 (12,980,000)
-------------- ------------
Estimated reserves as of December 31, 1996 2,239,000 41,446,000
============== ============

Proved developed reserves:

Oil Gas
(BBLS) (MCF)
--------------- -----------

December 31, 1993 745,000 24,665,000
=============== ==========

December 31, 1994 907,000 36,282,000
=============== ==========

December 31, 1995 1,794,000 40,323,000
============== ==========

December 31, 1996 1,867,000 39,288,000
============== ==========

F-19

Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows are computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the year-end estimated future production of proved oil and gas
reserves. Estimates of future development and production costs are based on
year-end costs and assume continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate of 10 per cent
per year to reflect the estimated timing of the future cash flows. The
standardized measure of discounted cash flows is the future net cash flows less
the computed discount.

The accompanying table reflects the standardized measure of discounted
future cash flows relating to proved oil and gas reserves as of the three years
ended December 31:

1996 1995 1994
-------------- -------------- -------------

Future cash inflows $ 210,875,000 $140,247,000 $ 88,893,000
Future development and production costs 61,822,000 50,723,000 32,197,000
--------------- -------------- -------------
Future net cash flows 149,053,000 89,524,000 56,696,000
Future income taxes 17,899,000 11,755,000 6,304,000
--------------- -------------- --------------
Future net cash flows after income taxes 131,154,000 77,769,000 50,392,000
10% annual discount (31,313,000) (14,848,000) (8,477,000)
--------------- -------------- --------------
Standardized measure after income taxes $ 99,841,000 $ 62,921,000 $ 41,915,000
============== ============= ============

Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
The accompanying table reflects the principal changes in the standardized
measure of discounted future net cash flows attributable to proved oil and gas
reserves for each of the three years ended December 31:

1996 1995 1994
------------- ------------- --------------

Beginning balance $ 62,921,000 $41,915,000 $ 47,379,000
Sales of oil and gas, net of production costs (11,027,000) (9,314,000) (11,047,000)
Net change in income taxes (4,116,000) (4,267,000) 5,562,000
Changes in price and production costs 44,088,000 11,498,000 (10,781,000)
Purchases of minerals in-place 45,521,000 34,415,000 ---
Sale of minerals in-place (10,518,000) --- ---
Revision of previous estimates, extensions &
discoveries, net (27,028,000) (11,326,000) 10,802,000
------------- ------------- -------------
Ending balance $ 99,841,000 $ 62,921,000 $ 41,915,000
============= ============== ==============

F-20

Report of Independent Public Accountants

To the Board of Directors
PANACO, Inc.

We have audited the accompanying Statement of Revenues and Direct Operating
Expenses of the Amoco Properties (acquired by PANACO, Inc. on October 8, 1996)
for each of the three years in the period ended December 31, 1995. This
statement and the notes thereto are the responsibility of PANACO, Inc.'s
management. Our responsibility is to express an opinion on the statement 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 Statement of Revenues and Direct Operating Expenses
is free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the statement. 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 Statement of Revenues and Direct Operating Expenses referred
to above presents fairly, in all material respects, the revenues and direct
operating expenses of the Amoco Properties for each of the three years in the
period ended December 31, 1995, in conformity with generally accepted accounting
principles.

Arthur Andersen LLP

Kansas City, Missouri
September 6, 1996

F-21

AMOCO PROPERTIES

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

Year Ended December 31

1995 1994 1993
---- ---- ----

Revenues:

Gas $ 8,769,000 $ 7,346,000 $ 8,459,000

Oil & Condensate 3,759,000 3,789,000 3,620,000
----------- ----------- -----------

Total Revenues $12,528,000 $11,135,000 $12,079,000
=========== =========== ===========

Direct Operating Expenses $ 2,991,000 $ 3,158,000 $ 2,798,000
============ ============ ============

See accompanying notes to this statement.

F-22

AMOCO PROPERTIES
NOTES TO THE STATEMENT OF REVENUES AND
DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements require the use of estimates, and when applicable,
specific information regarding significant estimates embodied in the financial
statements have been disclosed. The Statement of Revenues and Direct Operating
Expenses was prepared for purposes of complying with the rules and regulations
of the Securities and Exchange Commission and is not intended to be a complete
presentation of the financial position or results of operations of the Amoco
Properties.

Acquisition
The Amoco Properties were acquired by the Company on October 8, 1996 from Amoco
Production Company (seller) pursuant to the purchase and sale agreement dated
August 26, 1996. The properties to be acquired are Amoco Production Company's
existing interests in the following offshore blocks: East Breaks 160, East
Breaks 161, High Island (HI) 302, HI 309, HI 310, HI 330, HI 349, HI 474, HI
489, HI 499, a portion of the HI 475 Block, West Cameron (WC) 613, and WC 144.

Revenue Recognition
Revenues are recorded on an accrual basis, with volumes and prices being
estimated for properties during periods when actual production information is
not available. Revenues are recognized based on volumes of production taken and
sold by Amoco which is not materially different from the entitlement method for
the three year period ending December 31, 1995. For each of the periods
presented, Amoco sold substantially all of their production to a related party
at market based prices.

Direct Operating Expenses
Direct operating expenses include necessary and ordinary expenses to maintain
production. Insurance expense is not included since sufficient information is
not available from the Seller. Depreciation, depletion and amortization is not
included. No severance tax expense is included for the Amoco Properties, since
the production from federal offshore waters are not subject to state severance
taxes.

General, Administrative, and Overhead Expenses
General, administrative, and overhead expenses are not presented as sufficient
information is not available from the Seller.

Note 2 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
--------------------------------------------------------------------
(UNAUDITED)

Quantities of Oil and Gas Reserves
The estimates of proved developed and proved undeveloped reserve quantities of
the Amoco Properties at December 31, 1995 are based upon PANACO's computation at
December 31, 1996 and do not purport to reflect realizable values or fair market
values of the properties' reserves. It should be emphasized that reserve
estimates are inherently imprecise and accordingly, these estimates are expected
to change as future information becomes available. These are estimates only and
should not be construed as exact amounts. All reserves are located in the United
States. Reserve quantities for the Amoco Properties were not available at
December 31, 1992, 1993,

F-23

1994, and 1995, and the balances at those dates were derived from production
activity during 1993, 1994, 1995 and 1996.

Proved reserves are estimated reserves of natural gas and crude oil that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those expected to be
recovered through existing wells, equipment, and operating methods.

Oil Gas
Proved developed and (BBLS) (MCF)
undeveloped reserves

Estimated reserves as of
December 31, 1992 2,209,000 33,506,000

Production (216,000) (3,874,000)
--------- -----------

Estimated reserves as of
December 31, 1993 1,993,000 29,632,000

Production (236,000) (4,057,000)
--------- -----------

Estimated reserves as of
December 31, 1994 1,757,000 25,575,000

Production (216,000) (5,704,000)
------------ ------------

Estimated reserves as of
December 31,1995 1,541,000 19,871,000
========= ===========

Oil Gas
Proved developed reserves: (BBLS) (MCF)

December 31, 1993 1,720,000 27,533,000
========= ==========

December 31, 1994 1,484,000 23,476,000
========= ==========

December 31, 1995 1,268,000 17,772,000
========= ==========

Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows are computed by applying December 31, 1996 prices of oil and
gas (with consideration of price changes only to the extent provided by
contractual arrangements) to the estimated future production of proved oil and
gas reserves. Estimates of future development and production costs are based on
December 31, 1996 costs and assume continuation of existing economic conditions.
The estimated future net cash flows are then discounted using a rate of 10
percent per year to reflect the estimated timing of the future cash flows. The
standardized measure of discounted cash flows is the future net cash flows less
the discount at December 31, 1996.

F-24

The accompanying table reflects the standardized measure of discounted future
cash flows relating to the proved oil and gas reserves of the Amoco properties
as of the three years ended December 31:

1995 1994 1993
---- ---- ----

Future cash inflows $105,443,000 $117,971,000 $129,106,000
Future development
and production costs 34,309,000 37,300,000 40,458,000
------------ ------------ --------------
Future net cash flows 71,134,000 80,671,000 88,648,000
10% annual discount
to reflect timing of
cash flows 17,984,000 17,984,000 17,984,000
------------- -------------- --------------
Standardized measure
before income taxes $ 53,150,000 $ 62,687,000 $ 70,664,000
============ ============= =============

Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
The accompanying table reflects the changes in the standardized measure of
discounted future net cash flows from the sales of oil and gas, net of
production costs attributable to proved oil and gas reserves of the Amoco
properties for each of the three years ended December 31:

1995 1994 1993
---- ---- ----

Beginning balance $ 62,687,000 $ 70,664,000 $ 79,945,000
Sales of oil and gas,
net of production
costs 9,537,000 7,977,000 9,281,000
--------------- -------------- --------------

Ending balance $ 53,150,000 $ 62,687,000 $ 70,664,000
============= ============ ============

F-25