AMERICAN EXPLORATION CO, 424B4, 1996-11-04

AMERICAN EXPLORATION CO
424B4, 1996-11-04
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
FILED PURSUANT TO RULE 424(b)(4)
REGISTRATION NO. 333-13017
REGISTRATION NO. 333-15299
PROSPECTUS
- --------------------------------------------------------------------------------
3,927,055 Shares

AMERICAN EXPLORATION COMPANY
[AMERICAN EXPLORATION LOGO]
Common Stock
- --------------------------------------------------------------------------------

Of the shares of common stock, par value $.05 per share (the "Common Stock"),
offered hereby, 3,347,826 shares are being sold by American Exploration Company,
a Delaware corporation ("American Exploration" or the "Company") and 579,229
shares are being sold by the selling stockholders (the "Selling Stockholders").
The Company will not receive any proceeds from the sale of shares of Common
Stock by the Selling Stockholders. See "Selling Stockholders."

The Common Stock is listed on the American Stock Exchange Inc. (the "AMEX")
under the symbol "AX." On October 31, 1996, the last reported sales price of the
Common Stock on the AMEX was $13.00 per share. See "Price Range of Common Stock
and Dividend Policy."

SEE "RISK FACTORS" ON PAGES 10 TO 13 FOR A DISCUSSION OF CERTAIN MATERIAL
FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON
STOCK OFFERED HEREBY.

- --------------------------------------------------------------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
==============================================================================================
Underwriting Proceeds to
Price to Discounts and Proceeds to Selling
Public Commissions(1) Company(2) Stockholders
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Per Share............... $12.875 $0.71 $12.165 $12.165
- -----------------------------------------------------------------------------------------------
Total(3)................ $50,560,833 $2,788,209 $40,726,303 $7,046,321
===============================================================================================
</TABLE>

(1) The Company and the Selling Stockholders have agreed to indemnify the
several Underwriters against certain liabilities, including liabilities
under the Securities Act of 1933, as amended. See "Underwriting."

(2) Before deducting expenses payable by the Company estimated to be $645,000.

(3) The Company and one of the Selling Stockholders have granted the several
Underwriters 30-day over-allotment options to purchase up to 589,058
additional shares of Common Stock on the same terms and conditions set forth
above. If all such additional shares are purchased by the Underwriters, the
total Price to Public will be $58,144,955, the total Underwriting Discounts
and Commissions will be $3,206,440, the total Proceeds to Company will be
$47,200,200 and the total Proceeds to Selling Stockholders will be
$7,738,315. See "Underwriting."
- --------------------------------------------------------------------------------

The shares of Common Stock are offered by the several Underwriters, subject to
delivery by the Company and the Selling Stockholders and acceptance by the
Underwriters, to prior sale and to withdrawal, cancellation or modification of
the offer without notice. Delivery of the shares to the Underwriters is expected
to be made at the office of Prudential Securities Incorporated, One New York
Plaza, New York, New York, on or about November 6, 1996.

PRUDENTIAL SECURITIES INCORPORATED
DILLON, READ & CO. INC.
A.G. EDWARDS & SONS, INC.
October 31, 1996
<PAGE> 2

[MAP SHOWING CERTAIN FIELDS AND 3-D SURVEYS WITHIN
AMERICAN EXPLORATION COMPANY'S PRIMARY OPERATING AREAS]

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

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK OF
THE COMPANY AT LEVELS ABOVE THOSE WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE AMEX, IN THE OVER-THE-COUNTER
MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY
TIME.

2
<PAGE> 3

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the detailed
information, financial statements, including the notes thereto, and other data
set forth elsewhere in this Prospectus. Unless the context indicates otherwise,
(i) "American Exploration" or the "Company" refers to American Exploration
Company, a Delaware corporation, and its consolidated subsidiaries, (ii) all
information in this Prospectus has been adjusted to reflect the one-for-ten
reverse split of the Common Stock effected in June 1995 and (iii) all
information in this Prospectus assumes that the Underwriters' over-allotment
options will not be exercised. The pro forma information presented in this
Prospectus gives effect to the acquisition by the Company of certain properties
in March and September 1996 (the "March 1996 Acquisition" and "September 1996
Acquisition," respectively), the proposed sales of certain properties in
connection with the liquidation of oil and gas partnerships for which the
Company acts as a co-general partner (the "NYLOG Programs") and of certain
related properties (collectively, the "1996 Sales") and the application of the
net proceeds of the offering made by this Prospectus (the "Offering"). See
"--Recent Developments and Results," "Capitalization" and the Notes to the Pro
Forma Condensed Consolidated Financial Statements included elsewhere herein.

For definitions of certain oil and gas terms used in this Prospectus, see
"Glossary of Certain Oil and Gas Terms."

THE COMPANY

American Exploration is an independent company engaged in the exploration,
development, acquisition and production of oil and natural gas. The Company's
operations are conducted in the United States with exploration, development and
acquisition activities primarily concentrated in the Gulf of Mexico, South Texas
and the Smackover Trend in southwestern Arkansas.

On a pro forma basis as of June 30, 1996, the Company's proved reserves
totaled 13 MMBbls of oil and 145 Bcf of natural gas, or an aggregate of 37
MMBOE, with an SEC-10 Value of $225 million. Approximately 70% of these reserves
are developed, and approximately 62% are attributable to properties operated by
the Company. The Company also holds in excess of 200,000 net acres of
undeveloped properties and owns approximately 1,300 square miles of 3-D seismic
data and approximately 79,000 linear miles of 2-D seismic data. On a pro forma
basis, the Company's net production for the month of September 1996 averaged
5,100 Bbls of oil and 80,100 Mcf of natural gas per day, representing a 28%
increase over average daily BOE production for the second quarter of 1996.

Over the past four years, the Company has implemented a series of steps
that has resulted in a significant improvement in its oil and gas operating and
exploration capabilities, overhead and production costs, financial position and
cash operating margins. These steps include (i) hiring experienced personnel in
key management and operating positions, (ii) focusing exploration and
development activities in areas in which the Company believes it has competitive
advantages, (iii) acquiring properties held by certain institutional oil and gas
partnerships formed by the Company in the 1980s and (iv) disposing of over 250
properties, including the sale of the Company's interest in the Sawyer Field in
West Texas for $64 million in July 1995. Largely as a result of these steps, the
Company's operating margin has increased from $2.72 per BOE for the year ended
December 31, 1992 to $6.02 per BOE for the nine months ended September 30, 1996.
In addition, the Company's ratio of total debt to total capitalization has
decreased from 60% at December 31, 1992 to 28% on a pro forma basis at September
30, 1996.

BUSINESS STRATEGY

American Exploration's strategy is to increase per share reserves,
production, cash flow and earnings through exploration, development and
selective acquisitions within its core operating areas. The Company's strategy
is designed to capitalize on its competitive strengths, including the experience
and technical expertise of its operating personnel, a substantial seismic
database and a concentration of developed and undeveloped acreage in its core
operating areas. The principal features of this strategy follow.

3
<PAGE> 4

GEOGRAPHIC FOCUS. The Company's exploration, development and acquisition
activities are primarily focused in the Gulf of Mexico (with an emphasis on the
Texas State Waters area), South Texas (with an emphasis on the Wilcox Trend) and
the Smackover Trend in southwestern Arkansas. The Company believes that by
focusing its operations, it can achieve cost efficiencies and enhance its
ability to add new reserves. For 1996, over 90% of the Company's exploration and
development budget and all of its acquisition activities have been concentrated
in its core operating areas. The Company is also in the process of divesting
certain properties that are not consistent with its geographic focus (see
"-- Recent Developments and Results") and is reviewing the feasibility of
divesting various additional non-strategic properties.

ACTIVE DRILLING PROGRAM. The Company is engaged in an active drilling
program and attempts to maintain a project portfolio consisting of both high
risk, high potential exploration prospects and lower risk development projects.
The Company's exploration activities are generally concentrated in areas where
in-house geological knowledge and 2-D seismic data can be used to identify
prospect leads. The Company then attempts to establish large lease positions and
generally initiates or acquires 3-D seismic data to confirm prospects prior to
drilling. The Company typically shares the risks associated with its exploration
prospects with industry partners. In addition to internally generated
exploration prospects, the Company selectively participates in exploration
prospects initiated by other oil and gas companies. For 1996, the Company has
budgeted approximately $40 million for exploration and development and intends
to drill approximately 40 exploratory wells and 45 development wells. During the
first nine months of 1996, the Company spent approximately $18 million on
exploration and drilled 16 gross (7.0 net) wells, 31% of which were successfully
completed. During the same period, the Company spent approximately $12 million
on development and drilled 34 gross (11.7 net) wells, 85% of which were
successfully completed.

SELECTIVE ACQUISITIONS. The Company's acquisition strategy is to acquire
producing properties within its core operating areas that enhance its
competitive position, offer economies of scale and provide further development
and/or exploration potential. The Company seeks to acquire properties in which
it can obtain a significant ownership percentage and become the operator.
Through September 1996, the Company has invested $53 million, net of interests
being sold to a third party, to acquire interests in seven Gulf of Mexico
fields, four of which are operated by the Company. See "-- Recent Developments
and Results" and the Pro Forma Condensed Consolidated Financial Statements.

ADVANCED TECHNICAL CAPABILITIES. The Company makes extensive use of
advanced technologies, most notably 3-D seismic, computer-aided exploration and
specialized drilling applications such as short radius horizontal wells, to
better delineate or produce oil and gas reserves. The Company's experienced
staff of geologists and geophysicists performs all interpretation and seismic
mapping on in-house 3-D seismic workstations.

FINANCIAL FLEXIBILITY. The Company is committed to maintaining financial
flexibility in order to pursue its existing exploration and development projects
and to take advantage of future opportunities. The Company has taken a number of
steps over the past few years to reduce debt and improve its liquidity and
financial flexibility. As a result, the Company's ratio of total debt to EBITDA
(see Note 4 to "-- Summary Financial Data") for the prior 12 months decreased
from 5.2 as of December 31, 1992 to 1.3 on a pro forma basis as of September 30,
1996. The Company intends to use the net proceeds from the Offering to reduce
its outstanding bank debt. After giving effect to the proceeds from the
Offering, the Company's pro forma ratio of total debt to total capitalization as
of September 30, 1996 is expected to be 28%. See "Use of Proceeds,"
"Capitalization" and the Pro Forma Condensed Consolidated Financial Statements.

RECENT DEVELOPMENTS AND RESULTS

SEPTEMBER 1996 ACQUISITION. On September 27, 1996, the Company acquired
interests in two blocks in the Gulf of Mexico, High Island Block 116 and East
Cameron Block 328 (the "Zilkha II Properties"), for a purchase price of $39
million, net of interests being sold to a third party. The acquisition was
funded through borrowings under the Company's revolving bank credit agreement
(the "Credit Agreement"). The acquired properties added estimated proved
reserves (as estimated by the Company as of the date of acquisition) totaling
3.6 MMBbls of oil and 16.9 Bcf of natural gas. In September 1996, production
from the acquired

4
<PAGE> 5

interests was approximately 700 Bbls of oil and 17,000 Mcf of natural gas per
day. The Company plans to initiate a multi-well development drilling program on
East Cameron Block 328 before year-end 1996 and believes that both blocks have
additional unproved reserve potential through higher primary reserve recovery
and additional drilling.

MARCH 1996 ACQUISITION. On March 15, 1996, the Company and a subsidiary of
Dominion Resources, Inc. ("Dominion") acquired interests in five offshore blocks
in the Gulf of Mexico for a purchase price of approximately $56 million. The
Company's $14 million (25%) share of the March 1996 Acquisition was funded
through borrowings under the Credit Agreement. The acquired properties (the
"Zilkha I Properties") added estimated proved reserves (as estimated by the
Company as of the date of acquisition) totaling 600 MBbls of oil and 11.3 Bcf of
natural gas, net to the Company's interest. Three of the acquired properties,
High Island Block 45, South Marsh Island Block 133 and East Cameron Block 129,
which together represent substantially all of the proved reserve value, are
operated by the Company. In September 1996, the acquired properties produced an
average of approximately 670 Bbls of oil and 7,400 Mcf of natural gas per day,
net to the Company's interest. During the third quarter of 1996, the Company
completed the installation of production facilities on South Marsh Island Block
133 and a development well on East Cameron Block 129. The Company believes that
the acquired properties have additional reserve potential through higher primary
reserve recovery and the installation of gas compression.

PROPOSED 1996 SALES. The Company is in the process of selling interests in
approximately 70 properties, including those properties owned by the NYLOG
Programs. Proved reserves and production attributable to these properties have
not been included in the pro forma amounts set forth in this Prospectus. The
Company intends to use the estimated $8.6 million proceeds from the proposed
sales to reduce amounts outstanding under the Credit Agreement. The Company
believes that these sales, which are expected to be completed by year-end 1996,
will provide additional operating efficiencies.

THIRD QUARTER 1996 RESULTS. For a description of the Company's results of
operations for the quarter and nine months ended September 30, 1996, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Quarter and Nine Months Ended September 30, 1996 Compared to
Quarter and Nine Months Ended September 30, 1995."

PRIMARY OPERATING AREAS

GULF OF MEXICO. The Gulf of Mexico is the Company's most significant area
of exploration, development and acquisition activity and represents
approximately 60% of the Company's 1996 exploration and development budget. On a
pro forma basis, approximately 40% of total oil and gas production during
September 1996 and approximately 29% of the Company's total proved reserves at
June 30, 1996 were attributable to properties in the Gulf of Mexico. As of June
30, 1996, the Company held working interests in 41 offshore blocks covering
76,515 gross (28,788 net) undeveloped acres.

The Company's principal offshore exploration and development focus is the
Texas State Waters area. Beginning with a successful redevelopment program that
increased Brazos 440 Field gross production from 5,000 Mcf of natural gas per
day in February 1994 to over 25,000 Mcf of natural gas per day in October 1994,
the Company has developed a large area-wide project in which it holds 29,300
gross (18,200 net) acres. In 1995, the Company participated in a 400 square mile
3-D survey covering the Brazos area and has confirmed a number of prospect leads
previously identified using 2-D seismic data. Since January 1, 1994, the Company
has drilled five wells on its Brazos acreage, three of which were successful,
and as of September 30, 1996 it was drilling a sixth well. The Company intends
to further expand its Texas State Waters acreage and participate in additional
3-D seismic surveys.

SOUTH TEXAS. Approximately 30% of the Company's 1996 exploration and
development budget is allocated to its South Texas operating area. On a pro
forma basis, South Texas represented approximately 10% of total oil and natural
gas production during September 1996 and approximately 7% of the Company's total
proved reserves at June 30, 1996.

5
<PAGE> 6

American Exploration's principal exploration focus in South Texas is the
Yoakum Gorge project, located in Lavaca County, where the Company controls over
55,000 acres, holds a 52.5% working interest and is nearing completion of a 152
square mile proprietary 3-D survey. The initial phase of the 3-D data has
confirmed over 20 prospects in the shallow Frio and Yegua formations as well as
the deeper Upper and Lower Wilcox formations. The Company plans to commence
drilling 16 of these prospects in the fourth quarter of 1996.

SMACKOVER TREND. American Exploration's operations in the Smackover Trend
of southwestern Arkansas are focused primarily in the Midway and Buckner fields,
both of which are operated by the Company. The Company's ongoing strategy in
this area is to capitalize on the horizontal drilling expertise it has developed
in exploiting the Midway Field by applying this technology to other Smackover
fields. In 1995, the Company acquired various interests in the Buckner Field,
which is located approximately 11 miles from Midway. The Buckner Field, which is
geologically similar to Midway, has never been unitized and waterflooded. The
Company is working to unitize the field and plans to initiate a horizontal
drilling and waterflood project in 1997.

OTHER OPERATING AREAS. The Company's most significant properties outside of
its primary operating areas are the Bowdoin Field located in Montana, the
Bradshaw Field located near the Hugoton Field in Kansas and the Henderson Canyon
Field located in West Texas. During the first nine months of 1996, the Company
completed 11 gross (8.7 net) development wells in the Bradshaw Field and
increased net gas production by approximately 56% from an average of
approximately 8,000 Mcf per day in January 1996 to approximately 12,500 Mcf per
day in September 1996. In addition, the Company has a large number of
development locations in the Bowdoin Field that it intends to drill as necessary
to maintain production capacity at current levels.

THE OFFERING

<TABLE>
<S> <C>
Common Stock Offered:
By the Company............................................ 3,347,826 shares
By the Selling Stockholders............................... 579,229 shares
Total............................................. 3,927,055 shares
Common Stock to be Outstanding After the Offering (1)....... 15,155,567 shares
Use of Proceeds............................................. To reduce amounts outstanding
under the Credit Agreement.
The Company will not receive
any part of the proceeds from
the sale of shares by the
Selling Stockholders. See "Use
of Proceeds."
AMEX Symbol................................................. AX
</TABLE>

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(1) Excludes (i) up to approximately 1.8 million shares issuable upon conversion
of the Company's $450 Cumulative Convertible Preferred Stock, Series C, par
value $1.00 per share (the "Convertible Preferred Stock"), at a conversion
price of $15.00 per share, subject to adjustment in certain circumstances,
(ii) approximately 1.0 million shares issuable upon exercise of stock
options outstanding at September 30, 1996 at prices ranging from $11.50 to
$40.00 per share at a weighted average exercise price of $13.29 per share
and (iii) approximately 1.5 million shares issuable upon exercise of
warrants outstanding at September 30, 1996 at a weighted average exercise
price of $16.94 per share.

6
<PAGE> 7

SUMMARY FINANCIAL DATA
The following table sets forth certain summary historical and pro forma
financial data for the Company. The historical financial data was derived from
the consolidated financial statements of the Company. The pro forma summary of
operations data gives effect to the March 1996 Acquisition, the September 1996
Acquisition and the expected sale of certain assets acquired therein, the 1996
Sales and the application of the net proceeds from the Offering as if such
transactions had occurred on January 1, 1995. The pro forma balance sheet data
gives effect to the expected sale of certain assets acquired in the September
1996 Acquisition, the 1996 Sales and the application of the net proceeds from
the Offering as if such transactions had occurred on September 30, 1996. The pro
forma data for the year ended December 31, 1995 does not include results from
the High Island 116 well acquired in the September 1996 Acquisition because the
well did not produce during the period. Similarly, the pro forma data for the
nine months ended September 30, 1996 includes only two months of results from
the High Island 116 well. The well commenced production in August 1996 at a net
production rate of 300 Bbls of oil per day and 17,100 Mcf of natural gas per
day. The data in the following table should be read in conjunction with the Pro
Forma Condensed Consolidated Financial Statements, Management's Discussion and
Analysis of Financial Condition and Results of Operations and the Consolidated
Financial Statements and related Notes thereto appearing elsewhere herein.

<TABLE>
<CAPTION>
PRO FORMA
NINE
MONTHS
PRO FORMA NINE MONTHS ENDED ENDED
YEAR ENDED DECEMBER 31, YEAR ENDED SEPTEMBER 30, SEPTEMBER
-------------------------------- DECEMBER 31, ----------------- 30,
1993(1) 1994(2) 1995(2)(3) 1995 1995 1996 1996
-------- -------- ---------- ------------ ------- ------- ----------
(IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
SUMMARY OF OPERATIONS DATA:
Revenues:
Oil and gas sales................... $ 49,589 $ 50,033 $ 70,768 $ 65,238 $55,049 $52,263 $ 52,928
Other, net.......................... 8,569 1,326 11,166 772 10,352 912 912
-------- -------- ------- -------- ------- ------- -------
Total revenues.................. 58,158 51,359 81,934 66,010 65,401 53,175 53,840
-------- -------- ------- -------- ------- ------- -------
Costs and Expenses:
Production and operating............ 15,998 21,302 24,515 19,377 19,079 15,421 14,482
Depreciation, depletion and
amortization...................... 23,635 29,616 30,726 30,909 22,446 20,871 22,656
General and administrative.......... 7,413 10,035 7,472 7,528 4,683 4,450 4,450
Taxes other than income............. 4,601 5,710 5,760 4,956 4,413 4,254 3,862
Exploration......................... 7,554 2,559 4,826 4,826 3,269 9,152 9,152
Impairment.......................... 10,975 33,570 1,822 1,822 43 1,841 1,841
-------- -------- ------- -------- ------- ------- -------
Total costs and expenses........ 70,176 102,792 75,121 69,418 53,933 55,989 56,443
-------- -------- ------- -------- ------- ------- -------
Income (loss) from operations......... (12,018) (51,433) 6,813 (3,408) 11,468 (2,814) (2,603)
Interest expense...................... (6,847) (6,638) (5,481) (2,832) (4,853) (2,894) (2,606)
Other income (expense), net........... (321) (2,164) 145 147 (105) (63) (63)
-------- -------- ------- -------- ------- ------- -------
Income (loss) before extraordinary
item................................ (19,186) (60,235) 1,477 (6,093) 6,510 (5,771) (5,272)
Extraordinary gain on debt
extinguishment...................... -- 5,419 2,456 2,456 2,456 -- --
-------- -------- ------- -------- ------- ------- -------
Net income (loss)..................... (19,186) (54,816) 3,933 (3,637) 8,966 (5,771) (5,272)
Preferred stock dividends............. (75) (1,800) (1,800) (1,800) (1,350) (1,350) (1,350)
-------- -------- ------- -------- ------- ------- -------
Net income (loss) to common stock..... $(19,261) $(56,616) $ 2,133 $ (5,437) $ 7,616 $(7,121) $ (6,622)
======== ======== ======= ======== ======= ======= =======
Net income (loss) per common share:
Primary and fully diluted:
Loss before extraordinary item.... $ (2.77) $ (7.70) $ (0.03) $ (0.52) $ 0.43 $ (0.60) $ (0.44)
Net income (loss)................. (2.77) (7.02) 0.18 (0.36) 0.64 (0.60) (0.44)
OTHER FINANCIAL DATA:
EBITDA(4)............................. $ 37,224 $ 10,583 $ 33,981 $ 34,588 $27,493 $28,186 $ 30,182
Operating cash flow(5)................ 26,813 4,838 27,514 30,077 21,714 24,285 26,226
Total capital expenditures (6)........ 24,167 49,889 44,215 N/A 31,229 92,116 N/A
</TABLE>

<TABLE>
<CAPTION>
PRO FORMA
SEPTEMBER 30, SEPTEMBER 30,
1996 1996
------------- --------------
<S> <C> <C>
SUMMARY OF BALANCE SHEET DATA:
Working capital (deficit).......................................................... $ (1,623) $(16,007)
Total assets....................................................................... 233,363 218,979
Long-term debt, excluding current obligations...................................... 105,000 50,528
Total stockholders' equity......................................................... 87,506 127,594
</TABLE>

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(1) The Company received aggregate proceeds of approximately $35 million for the
conveyance of approximately 40% of its interest in the Henderson Canyon
Field in March 1993 and the sale of its Canadian assets in mid-1993.

(2) The Company purchased investors' interests in certain institutional oil and
gas partnerships formed by the Company in the 1980s (the "APPL Programs") in
1994 and 1995 for 4.6 million shares of Common Stock and $40.1 million in
cash (the "APPL Consolidation").

(3) The Company sold its interest in the Sawyer Field for $64 million in July
1995.

(4) EBITDA is defined for this purpose as net income (loss) plus interest,
income taxes, depreciation, depletion and amortization, exploration expense,
impairment expense and loss on sales of oil and gas properties, less gain on
sales of oil and gas properties and extraordinary gain from extinguishment
of debt. EBITDA should not be considered as an alternative to earnings
(loss) as an indicator of the Company's financial performance or to cash
flow as a measure of liquidity. See the Consolidated Statements of
Operations included in the Consolidated Financial Statements appearing
elsewhere herein.

(5) Cash flow from operations before working capital changes and after preferred
dividends.

(6) Excludes the acquisition of properties in exchange for the issuance of
Common Stock, principally relating to the APPL Consolidation.

7
<PAGE> 8

SUMMARY OPERATING DATA

The table below sets forth certain operating information of the Company for
the periods presented.

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
---------------------------------- -------------------
1993(2) 1994(3) 1995(3)(4) 1995(3) 1996
------- ------- ---------- ------- -------
<S> <C> <C> <C> <C> <C>
AVERAGE SALES PRICE(1):
Gas ($/Mcf)........................... $ 1.92 $ 1.90 $ 1.74 $ 1.70 $ 1.88
Oil ($/Bbl)........................... 16.01 15.39 16.83 16.87 16.87
BOE ($/BOE)........................... 12.99 12.67 12.30 12.05 13.17
PRODUCTION DATA:
Gas (MMcf)............................ 15,336 16,241 24,450 19,866 15,772
Oil (MBbls)........................... 1,261 1,241 1,680 1,258 1,340
MBOE.................................. 3,817 3,948 5,755 4,569 3,969
UNIT DATA ($/BOE):
Oil and gas sales..................... $ 12.99 $ 12.67 $ 12.30 $ 12.05 $ 13.17
Production and operating costs........ 4.19 5.40(5) 4.26 4.18 3.89
Taxes other than income............... 1.21 1.45 1.00 0.97 1.07
General and administrative expense.... 1.94 2.54(6) 1.30 1.02 1.12
Interest expense...................... 1.79 1.68 0.95 1.06 0.73
Preferred stock dividends............. 0.02 0.46 0.31 0.30 0.34
------- ------- ------- ------- ------
Operating margin...................... $ 3.84 $ 1.14 $ 4.48 $ 4.52 $ 6.02
======= ======= ======= ======= ======
</TABLE>

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(1) Prices reflect impact of hedging gains and losses.

(2) The Company received aggregate proceeds of approximately $35 million for the
conveyance of approximately 40% of its interest in the Henderson Canyon
Field in March 1993 and the sale of its Canadian assets in mid-1993.

(3) The Company purchased investors' interests in the APPL Programs in 1994 and
1995 for 4.6 million shares of Common Stock and $40.1 million in cash.

(4) The Company sold its interest in the Sawyer Field for $64 million in July
1995.

(5) Includes $2.4 million, or $.61 per BOE, for remediation and restoration
costs incurred in 1994.

(6) Includes $2.0 million, or $.51 per BOE, for severance costs incurred in
1994.

8
<PAGE> 9

SUMMARY RESERVE DATA

The following table sets forth summary data with respect to the estimated
proved oil and gas reserves and related present value of estimated future net
revenues of the Company's properties as of June 30, 1996 on a historical basis
and on a pro forma basis after giving effect to the September 1996 Acquisition
and the 1996 Sales. Such estimates on a historical basis are based upon (i) the
quantities of reserves set forth in a reserve report prepared by Netherland,
Sewell & Associates, Inc., independent petroleum engineers, as of December 31,
1995 with respect to the properties owned by the Company as of such date, (ii)
adjustments to such December 31, 1995 reserves made by the Company to reflect
production and drilling activity after such date, which adjustments have been
audited by Netherland, Sewell & Associates, Inc. as set forth in their report
dated October 8, 1996 and included in Appendix A hereto, and (iii) reserve
estimates set forth in a reserve report prepared by William M. Cobb &
Associates, Inc., petroleum engineering consultants, as of June 30, 1996, a copy
of which is included in Appendix A hereto (the "Cobb Report"), with respect to
the properties acquired in the March 1996 Acquisition. Such estimates on a pro
forma basis are based on (i) the historical basis estimates as of June 30, 1996
as described above, (ii) adjustments to such June 30, 1996 estimates made by the
Company to remove reserves attributable to the 1996 Sales and (iii) reserve
estimates set forth in the Cobb Report with respect to the properties acquired
in the September 1996 Acquisition. The estimates of the SEC-10 Value of the
reserves are based upon prices as of June 30, 1996, except in those instances in
which fixed and determinable gas price escalations are covered by contracts. The
prices used as of June 30, 1996 averaged $18.19 per Bbl of oil and $2.25 per Mcf
of natural gas. There are numerous uncertainties inherent in estimating
quantities of proved oil and gas reserves and in projecting future rates of
production and future net cash flows, and reserve estimates may differ
significantly from the quantities of oil and gas that are ultimately recovered.
See "Risk Factors -- Estimates of Reserves and Future Net Revenues" and
"Business -- Reserves."

<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
-----------------------------------------------------------------------
HISTORICAL PRO FORMA
---------------------------------- ----------------------------------
PROVED PROVED PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------- --------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Estimated proved reserves:
Oil (MBbls)................... 9,165 1,351 10,516 8,857 4,390 13,247
Gas (MMcf).................... 112,911 22,428 135,339 104,542 40,639 145,181
MBOE.......................... 27,984 5,089 33,073 26,281 11,163 37,444
Present value of estimated
future net revenue before
income taxes (discounted at
10% per annum) (in
thousands).................... $ 168,513 $22,263 $190,776 $ 162,303 $62,745 $225,048
</TABLE>

9
<PAGE> 10

RISK FACTORS

Prospective investors should carefully consider the following risk factors,
in addition to the other information set forth in this Prospectus, in connection
with an investment in the shares of Common Stock offered hereby.

This Prospectus includes certain statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). All
statements, other than statements of historical facts, included in this
Prospectus that address activities, events or developments that the Company
expects, believes or anticipates will or may occur in the future, including such
matters as future capital, development and exploration expenditures (including
the amount and nature thereof), drilling of wells, reserve estimates (including
estimates of future net revenues associated with such reserves and the present
value of such future net revenues), future production of oil and gas, repayment
of debt, business strategies, expansion and growth of the Company's operations
and other such matters are forward-looking statements. These statements are
based on certain assumptions and analyses made by the Company in light of its
experience and its perception of historical trends, current conditions, expected
future developments and other factors it believes are appropriate in the
circumstances. Such statements are subject to a number of assumptions, risks and
uncertainties, including the risk factors discussed below, general economic and
business conditions, the business opportunities (or lack thereof) that may be
presented to and pursued by the Company, changes in law or regulations and other
factors, many of which are beyond the control of the Company. Prospective
investors are cautioned that any such statements are not guarantees of future
performance and that actual results or developments may differ materially from
those projected in the forward-looking statements.

INDUSTRY CONDITIONS; VOLATILITY OF OIL AND NATURAL GAS PRICES; HEDGING
ACTIVITIES. The Company's revenues, cash flow, profitability and future rate of
growth, as well as the carrying value of its oil and natural gas properties, are
substantially dependent upon the prices of oil and natural gas, which
historically have been volatile and are likely to continue to be volatile.
Various factors beyond the control of the Company affect prices of oil and
natural gas, including worldwide and domestic supplies of and demand for oil and
gas; political and economic conditions; weather conditions; the ability of the
members of the Organization of Petroleum Exporting Countries to agree on and
maintain price and production controls; political instability or armed conflict
in oil-producing regions; the price of foreign imports; the level of consumer
demand; the price and availability of alternative fuels; and changes in existing
federal and state regulations. Any significant decline in oil or gas prices
could have a material adverse effect on the Company's operations, financial
condition and level of development and exploration expenditures and could result
in a reduction of the Company's borrowing base under the Credit Agreement,
thereby reducing the amount of credit available to the Company to fund its
exploration, development and acquisition activities.

Part of the Company's business strategy is to reduce its exposure to the
volatility of oil and natural gas prices by entering into financial arrangements
designed to protect against price declines, including swaps and futures
agreements. The Company's objective is to reduce the risk that a sharp drop in
oil or natural gas prices will cause the Company to defer various capital
spending projects. In certain circumstances, significant reductions in
production, due to unforeseen events, could require the Company to make payments
under the hedge agreements even though such payments are not offset by
production. To reduce this risk, the Company strives to keep a percentage of its
production unhedged. Hedging will also prevent the Company from receiving the
full advantage of increases in oil or natural gas prices above the amount
specified in the hedge. Based upon average daily production during September
1996, the Company's hedge agreements covered approximately 67% and 36% of the
Company's daily average oil and natural gas production, respectively, during
such month. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Hedging Activity."

INCURRENCE OF LOSSES AND WORKING CAPITAL DEFICITS. Although the Company
reported net income available for Common Stock of $2.1 million in 1995, the
Company experienced significant net losses in 1993, 1994 and the nine months
ended September 30, 1996. The Company's results of operations will be

10
<PAGE> 11

significantly impacted by the level of exploration expenses and by the costs of
drilling dry exploratory wells, which are charged to expense under the
successful efforts method of accounting followed by the Company. During the
first nine months of 1996, the Company incurred a loss of $5.8 million. There
can be no assurance that the Company will not experience losses in the future.
If the Company experiences significant losses, its ability to maintain
compliance with financial covenants in its debt instruments could be adversely
affected.

Under certain circumstances, the Company may be required to write down the
book value of the Company's proved oil and natural gas properties or recognize
an impairment in the book value of its unproved properties. The Company has
recorded write-downs of its oil and natural gas properties during the last few
years.

The Company has incurred working capital deficits in the ordinary course of
its business and expects to continue to operate with such working capital
deficits in the future. The Company's working capital deficits reflect, among
other items, payables, short-term debt (including the current portion of
long-term debt), taxes and other amounts that are due within one year. The
Company generally intends to fund its working capital deficits through operating
cash flow and bank borrowings, as available. Any material adverse developments
relating to the Company's operating cash flow or its ability to borrow under the
Credit Agreement or any future bank credit facility could have a material
adverse effect on the Company's financial condition. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

RISKS OF DEVELOPMENT DRILLING, ACQUISITIONS AND EXPLORATION; REPLACEMENT OF
RESERVES. The Company intends to utilize its cash flow from operations and
borrowing capacity under the Credit Agreement to fund the Company's exploration,
development and exploitation activities and property acquisitions. The decision
to develop, exploit, purchase or explore a property will depend in part on the
Company's assessment of recoverable reserves, future oil and natural gas prices
and operating costs, potential environmental and other liabilities and other
factors that are beyond the control of the Company. Such assessments are
necessarily inexact and their accuracy is inherently uncertain. Even if
geophysical and geological analyses and engineering studies, the results of
which are often inconclusive or subject to varying interpretations, indicate
high reserve potential of a prospect or project, there can be no assurance that
the Company's development, exploitation, acquisition or exploration activities
will result in additional reserves or that the Company will be successful in
drilling productive wells.

In general, the volume of production from oil and natural gas properties
declines as reserves are depleted. Except to the extent that the Company
conducts successful development, exploitation and exploration activities or
acquires properties containing proved reserves, or both, the proved reserves of
the Company will decline as reserves are produced. As is generally the case in
the Gulf Coast region, many of the Company's producing properties are
characterized by a high initial production rate followed by a steep decline in
production. As a result, the Company's future oil and natural gas production is
highly dependent upon its level of success in finding, acquiring, developing and
exploiting additional reserves.

ESTIMATES OF RESERVES AND FUTURE NET REVENUES. There are numerous
uncertainties inherent in estimating quantities of proved oil and gas reserves
and in projecting future rates of production and the timing and results of
development expenditures. Oil and gas reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact way, and estimates of other engineers might differ from
those included in this Prospectus. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered, which differences may be significant. In
addition, estimates of the Company's future net revenues from proved reserves
and the present value thereof are based on certain assumptions regarding future
oil and gas prices, production levels and operating and development costs that
may not prove to be correct. Any significant variance in these assumptions could
materially affect the Company's estimated quantity of reserves and future net
revenues therefrom. See "Business -- Reserves."

OPERATING HAZARDS AND UNINSURED RISKS. The Company's operations are subject
to all of the risks normally incident to the exploration for and the development
and production of oil and gas, including

11
<PAGE> 12

blowouts, cratering, uncontrollable flows of oil, gas or well fluids, fires,
pollution and other environmental risks. These hazards could result in
substantial losses to the Company due to injury and loss of life, severe damage
to and destruction of property and equipment, pollution and other environmental
damage and suspension of operations. In addition, offshore operations are
subject to a variety of operating risks peculiar to the marine environment, such
as hurricanes or other adverse weather conditions, to more extensive
governmental regulation and to interruption or termination of operations by
governmental authorities based on environmental or other considerations.

Although the Company maintains insurance coverage considered to be
customary in the industry, it is not fully insured against certain of these
risks, either because such insurance is not available or because of high premium
costs. The occurrence of a significant event against which the Company is not
fully insured could have a material adverse effect on the Company's financial
position.

GOVERNMENT REGULATION AND ENVIRONMENTAL RISKS. The Company's business is
subject to certain federal, state and local laws and regulations relating to
taxation, exploration for and development and production of oil and gas and
environmental and safety matters. Although the Company believes that its
operations are in compliance with applicable environmental regulations, risks of
substantial costs and liabilities are inherent in the operations of companies in
the oil and gas industry, and there can be no assurance that such costs and
liabilities will not be incurred. A variety of federal and state laws and
regulations govern the environmental aspects of oil and gas production,
handling, storage, transportation and processing and may, in addition to other
laws, impose liability in the event of discharges (whether or not accidental),
failure to notify the proper authorities of a discharge and other failures to
comply with those laws. The Company does not believe that its environmental
risks are materially different from those of comparable companies in the oil and
gas industry. Nevertheless, there can be no assurance that future laws and
regulations, including environmental laws and regulations, will not adversely
affect the Company's operations and financial condition.

CAPITAL-INTENSIVE INDUSTRY; LIMITS ON ACCESS TO CAPITAL. The business of
developing, exploring for and acquiring oil and gas reserves is capital
intensive, and the Company will require substantial amounts of cash for planned
expenditures for development and exploratory drilling activities, acquisitions
of reserves and debt service. The ability of the Company to generate cash flow
and obtain financing from third parties will be dependent on the Company's
future performance and liquidity. Substantially all of the Company's assets are
encumbered, and the Company's ability to borrow additional funds is limited by
the terms of the purchase agreements relating to its 11% senior subordinated
notes (the "Subordinated Notes") and the Credit Agreement. Pursuant to the
Credit Agreement, the Company's borrowing base is subject to redetermination on
a semiannual basis. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Capital Resources and Liquidity."

COMPETITION. The Company operates in a highly competitive environment. The
Company competes with major oil and gas companies, independent producers,
drilling and production purchase programs and individual producers and operators
for the acquisition of desirable oil and gas properties, as well as for the
equipment and labor required to develop and operate such properties. Many of
these competitors have financial and other resources substantially greater than
those of the Company. See "Business -- Oil and Gas Marketing and Competition."

SHARES ELIGIBLE FOR FUTURE SALE. Sales of substantial amounts of Common
Stock by current stockholders or by warrant holders could adversely affect the
prevailing market price of the Common Stock and impair the Company's ability to
raise capital by issuing equity securities. Of the 11.8 million shares of Common
Stock outstanding prior to the Offering, the Company has granted registration
rights with respect to approximately 5.6 million shares. Substantially all of
the remainder of such 11.8 million shares are freely tradeable. In addition, (i)
up to approximately 1.8 million shares are issuable upon conversion of the
Convertible Preferred Stock at a conversion price of $15.00 per share, subject
to adjustment in certain circumstances, (ii) approximately 1.0 million shares
are issuable upon exercise of stock options outstanding at September 30, 1996 at
prices ranging from $11.50 to $40.00 per share at a weighted average exercise
price of $13.29 per share and (iii) approximately 1.5 million shares are
issuable upon exercise of warrants outstanding at September 30, 1996 at a
weighted average exercise price of $16.94 per share. The holders of such
warrants have been granted

12
<PAGE> 13

certain registration rights with respect to the shares of Common Stock issuable
upon exercise of the warrants, and the shares of Common Stock issuable upon
conversion of the Convertible Preferred Stock have been registered under the
Securities Act. In connection with the Offering, the Company, the officers and
directors of the Company, the Selling Stockholders and certain other
stockholders of the Company have agreed not to sell or otherwise dispose of
shares of Common Stock held by them following the Offering for a period of 90
days after the date of this Prospectus. See "Underwriting."

NO DIVIDENDS ON COMMON STOCK. The Company has not declared or paid any
dividends on the Common Stock and does not anticipate declaring or paying any
dividends on the Common Stock for the foreseeable future. In addition, the terms
of the Credit Agreement and purchase agreements relating to its Subordinated
Notes also impose limitations upon the declaration and payment of dividends.

ANTI-TAKEOVER PROVISIONS; STOCKHOLDER RIGHTS PLAN. The Board of Directors
of the Company ("Board of Directors") is authorized to issue additional shares
of preferred stock and could, without stockholder approval, issue such preferred
stock with voting, liquidation preference, dividend and other rights superior to
those of the Common Stock. The issuance of such preferred stock could adversely
affect the voting power of holders of the Common Stock and could have the effect
of delaying, deferring or preventing a change in control of the Company or the
removal of existing management. The terms of the Company's outstanding
Convertible Preferred Stock, with its voting and special conversion rights,
could also have a similar effect. In addition, in 1993 the Company adopted a
stockholder rights plan and shortly thereafter distributed rights to each
outstanding holder of Common Stock. See "Description of Capital
Stock -- Stockholder Rights Plan." While the Company believes that the rights
plan is designed to strengthen the Company's ability to negotiate with potential
acquirors and to protect stockholders from coercive or abusive takeover tactics,
the overall effect of the rights plan may be to delay, defer or prevent a change
in control of the Company. The Company has no specific plans or arrangements for
the issuance of any series of preferred stock other than the issuance of the
preferred stock issuable pursuant to the terms of the Company's stockholder
rights plan.

13
<PAGE> 14

THE COMPANY

American Exploration is an independent company engaged in the exploration,
development, acquisition and production of oil and natural gas. The Company's
operations are conducted in the United States with exploration, development and
acquisition activities concentrated in the Gulf of Mexico, South Texas and the
Smackover Trend in southwestern Arkansas.

The Company was incorporated in Delaware in 1980. From inception through
1991, the Company was principally engaged in the acquisition and management of
oil and gas properties, both for its own account and in partnership with
institutional and non-institutional investors. During this period, the Company
completed over 30 acquisitions on behalf of the Company and its partners. This
period culminated with the acquisition in 1990 and 1991 of Hershey Oil
Corporation and Conquest Exploration Company, respectively. The Company conveyed
approximately 40% of its interest in the Henderson Canyon Field in March 1993
and sold its Canadian assets in mid-1993. In 1994 and 1995, the Company
completed the APPL Consolidation for $40.1 million cash and the issuance of 4.6
million shares of Common Stock. In July 1995, the Company accepted an
unsolicited offer to purchase its interest in the Sawyer Field in West Texas,
the Company's largest property, for $64.0 million. Proceeds from the sale
enabled the Company to repay bank debt and reduce debt as a percentage of
capitalization to 30% at year-end 1995 from 53% at year-end 1994.

The Company is in the process of liquidating the NYLOG Programs, a series
of publicly registered oil and gas partnerships co-managed by a subsidiary of
the Company and a subsidiary of New York Life Insurance Company ("New York
Life"). The co-general partners of the NYLOG Programs have received bids from
third parties and are negotiating to sell the properties owned by the NYLOG
Programs and certain additional property interests of the Company. The Company
anticipates that the 1996 Sales will be completed during the fourth quarter of
1996, with estimated net proceeds to the Company of $8.6 million. See
"Business -- Legal Proceedings." The effect of the 1996 Sales is reflected in
the pro forma financial statements included elsewhere herein. See the Pro Forma
Condensed Consolidated Financial Statements.

The Company's executive offices are located at 1331 Lamar, Suite 900,
Houston, Texas 77010, and its telephone number is (713) 756-6000.

USE OF PROCEEDS

The Company's proceeds, after deducting underwriting discounts and
commissions and estimated offering expenses payable by the Company, from the
sale of the shares of Common Stock offered by the Company are estimated to be
approximately $40.1 million (approximately $46.6 million if the Underwriters'
over-allotment options are exercised in full). These net proceeds will be used
to reduce outstanding indebtedness under the Credit Agreement, which
indebtedness was incurred to finance the March 1996 Acquisition and the
September 1996 Acquisition and for general working capital purposes. Following
the application of the net proceeds from the Offering, the Company will have
approximately $59.5 million of borrowing capacity available under the Credit
Agreement, which will be available for exploration and development activities,
acquisitions and general corporate purposes. The Company will not receive any of
the proceeds from the sale of Common Stock by the Selling Stockholders.

Principal payments under the Credit Agreement are scheduled to be repaid in
ten quarterly installments commencing September 30, 1999 unless extended by the
lenders thereunder, and at September 30, 1996, the average interest rate on
amounts outstanding under the Credit Agreement was 8.3%.

14
<PAGE> 15

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock is listed on the AMEX under the symbol "AX." As of
September 30, 1996, the Company had approximately 4,470 stockholders of record.

The following table sets forth the high and low reported closing sales
prices for the Common Stock for the quarters indicated.

PRICE RANGE OF COMMON STOCK

<TABLE>
<CAPTION>
HIGH LOW
---- ----
<S> <C> <C>
YEAR ENDED DECEMBER 31, 1994
First Quarter...................................................... $ 18 3/4 $ 13 3/4
Second Quarter..................................................... 15 11 1/4
Third Quarter...................................................... 15 11 7/8
Fourth Quarter..................................................... 13 3/4 8 3/4
YEAR ENDED DECEMBER 31, 1995
First Quarter...................................................... $ 10 $ 8 3/4
Second Quarter..................................................... 10 7/8 8 1/8
Third Quarter...................................................... 12 1/8 10 3/8
Fourth Quarter..................................................... 11 7/8 9 5/8
YEAR ENDED DECEMBER 31, 1996
First Quarter...................................................... $ 12 $ 10 5/8
Second Quarter..................................................... 13 1/2 10 5/8
Third Quarter...................................................... 14 11 7/8
Fourth Quarter (through October 31, 1996).......................... 13 11 7/8
</TABLE>

The Company has not declared or paid any dividends on the Common Stock and
does not expect to declare or pay dividends on the Common Stock for the
foreseeable future. Declaration or payment of dividends on the Common Stock is
currently restricted by the terms of various agreements relating to outstanding
indebtedness of the Company.

15
<PAGE> 16

CAPITALIZATION

The following table sets forth the capitalization of the Company as of
September 30, 1996 and as adjusted to reflect (i) the incurrence of $39 million
in long-term indebtedness to fund the September 1996 Acquisition, (ii) the
application of the estimated net proceeds from the Offering of $40.1 million to
repay amounts outstanding under the Credit Agreement and (iii) the application
of the estimated net proceeds from the 1996 Sales of $8.6 million to repay
amounts outstanding under the Credit Agreement. The table should be read in
conjunction with the Consolidated Financial Statements of the Company and the
related Notes included elsewhere herein.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
-----------------------
AS
ACTUAL ADJUSTED
--------- ---------
(IN THOUSANDS, EXCEPT
SHARE AMOUNTS)
<S> <C> <C>
Long-term debt:
Credit Agreement.................................................... $ 70,000 $ 15,528
Subordinated Notes.................................................. 35,000 35,000
--------- ---------
Total long-term debt........................................ 105,000 50,528
--------- ---------
Stockholders' equity:
Preferred stock, $1.00 par value, 100,000 shares authorized; 4,000
shares of Convertible Preferred Stock (represented by Depositary
Shares) issued and outstanding................................... 4 4
Common stock, $.05 par value, 50,000,000 shares authorized,
11,807,741 shares issued and outstanding(1)...................... 590 757
Additional paid-in capital.......................................... 276,658 316,579
Accumulated deficit................................................. (189,664) (189,664)
Unearned compensation............................................... (79) (79)
Notes receivable from officers...................................... (3) (3)
--------- ---------
Total stockholders' equity.................................. 87,506 127,594
--------- ---------
Total capitalization........................................ $ 192,506 $ 178,122
========= =========
</TABLE>

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

(1) Does not reflect (i) approximately 1.0 million shares issuable upon exercise
of outstanding stock options at prices ranging from $11.50 to $40.00 per
share at a weighted average exercise price of $13.29 per share or (ii)
approximately 1.5 million shares issuable upon exercise of warrants at a
weighted average exercise price of $16.94 per share. See "Description of
Capital Stock -- Warrants."

16
<PAGE> 17

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
INTRODUCTION TO PRO FORMA FINANCIAL STATEMENTS

The following unaudited pro forma condensed consolidated financial
statements (the "Pro Forma Statements") give effect to (i) that portion of the
APPL Consolidation that was completed in the first half of 1995 for a purchase
price of approximately $9 million, (ii) the 1995 sales of interests in several
other fields for aggregate proceeds of approximately $2.5 million (the "1995
Sales"), (iii) the Sawyer Sale in July 1995 for proceeds of $64.0 million, (iv)
the application of the estimated net proceeds from the Offering of $40.1 million
to repay amounts outstanding under the Credit Agreement, (v) the March 1996
Acquisition and the September 1996 Acquisition and (vi) the 1996 Sales. The
Sawyer Sale, the 1995 Sales and the APPL Consolidation are sometimes
collectively referred to in the Pro Forma Statements as the "1995 Transactions."

The pro forma statements of operations for the nine months ended September
30, 1996 and for the year ended December 31, 1995 have been prepared assuming
that each of the transactions described above was consummated as of January 1,
1995. The pro forma statements of operations for the year ended December 31,
1995 do not include results from the High Island 116 well acquired in the
September 1996 Acquisition because the well did not produce during the period.
Similarly, the pro forma data for the nine months ended September 30, 1996
includes only two months of results from the High Island 116 well, which results
reflect the Company's acquired interest net of interests being sold to a third
party. The well commenced production in August 1996 at a net production rate of
300 Bbls of oil per day and 17,100 Mcf of natural gas per day. The pro forma
balance sheet was prepared assuming that the Offering, the expected sale of
certain assets acquired in the September 1996 Acquisition and the 1996 Sales
were consummated as of September 30, 1996.

The Pro Forma Statements are not necessarily indicative of the financial
results that would have occurred had the Company completed each of the
transactions described above as of January 1, 1995 or September 30, 1996, as the
case may be. Furthermore, future results may vary significantly from the results
reflected in the Pro Forma Statements due to changes in production levels,
changes in market prices for oil and gas, future expenditures for acquisitions,
development drilling and exploration and other factors. The Pro Forma Statements
should be read in conjunction with Management's Discussion and Analysis of
Financial Condition and Results of Operations and the Consolidated Financial
Statements and related Notes thereto appearing elsewhere in this Prospectus.

17
<PAGE> 18

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 1996
(IN THOUSANDS)
(UNAUDITED)

ASSETS

<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ---------
<S> <C> <C> <C>
Current assets:
Cash and temporary cash investments..................... $ 6,780 $ 6,780
Accounts receivable..................................... 11,203 11,203
Assets held for sale.................................... 14,384 $ (8,634)(a) --
(5,750)(b)
Other current assets.................................... 2,158 2,158
-------- -------- --------
Total current assets............................ 34,525 (14,384) 20,141
Property, plant and equipment, net........................ 195,850 195,850
Other assets.............................................. 2,988 2,988
-------- -------- --------
Total assets.................................... $ 233,363 $ (14,384) $ 218,979
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable........................................ $ 15,670 $ 15,670
Payable to partnerships................................. 1,678 1,678
Accrued liabilities..................................... 18,800 18,800
-------- -------- --------
Total current liabilities....................... 36,148 36,148
Long-term debt............................................ 105,000 $ (5,750)(c) 50,528
(8,634)(d)
(40,088)(e)
Other long-term liabilities............................... 4,709 4,709
Stockholders' equity...................................... 87,506 40,088 (e) 127,594
-------- -------- --------
Total liabilities and stockholders' equity...... $ 233,363 $ (14,384) $ 218,979
======== ======== ========
</TABLE>

18
<PAGE> 19

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996
(IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)
(UNAUDITED)

<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS
---------------------------------------------------------
MARCH SEPTEMBER
1996 1996
HISTORICAL ACQUISITION ACQUISITION 1996 SALES OFFERING PRO FORMA
---------- ----------- ----------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
REVENUES:
Oil and gas sales............. $ 52,263 $ 1,964(f) $ 4,467(h) $ (5,766)(j) $52,928
Other revenues, net........... 912 912
------- ------- ------- ------ ------ -------
Total revenues......... 53,175 1,964 4,467 (5,766) 53,840
------- ------- ------- ------ ------ -------
COSTS AND EXPENSES:
Production and operating...... 15,421 109(f) 963(h) (2,011)(j) 14,482
Depreciation, depletion and
amortization................ 20,871 728(f) 2,370(h) (1,313)(j) 22,656
General and administrative.... 4,450 4,450
Taxes other than income....... 4,254 (392)(j) 3,862
Exploration................... 9,152 9,152
Impairment.................... 1,841 1,841
------- ------- ------- ------ ------ -------
Total costs and
expenses............. 55,989 837 3,333 (3,716) 56,443
------- ------- ------- ------ ------ -------
INCOME (LOSS) FROM OPERATIONS... (2,814) 1,127 1,134 (2,050) (2,603)
Interest and other expense,
net........................... (2,957) (280)(g) (2,355)(i) 518(k) $2,405(l) (2,669)
------- ------- ------- ------ ------ -------
INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM............ (5,771) 847 (1,221) (1,532) 2,405 (5,272)
Preferred stock dividends....... (1,350) (1,350)
------- ------- ------- ------ ------ -------
INCOME (LOSS) TO COMMON STOCK
BEFORE EXTRAORDINARY ITEM..... $ (7,121) $ 847 $(1,221) $ (1,532) $2,405 $(6,622)
======= ======= ======= ====== ====== =======
LOSS BEFORE EXTRAORDINARY ITEM
PER COMMON SHARE:
Primary and fully diluted..... $ (0.60) $ (0.44)
======= =======
NUMBER OF COMMON AND EQUIVALENT
SHARES:
Primary and fully diluted..... 11,811 3,348(m) 15,159
======= ====== =======
</TABLE>

19
<PAGE> 20

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1995
(IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)
(UNAUDITED)

<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS
---------------------------------------------------------------------------
MARCH SEPTEMBER
1995 1996 1996
HISTORICAL TRANSACTIONS ACQUISITION ACQUISITION 1996 SALES OFFERING PRO FORMA
---------- ------------ ----------- ----------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
REVENUES:
Oil and gas sales...... $ 70,768 $ (9,450)(n) $ 7,513(f) $ 2,886(h) $ (6,479)(j) $ 65,238
Gain (loss) on sales of
oil and gas
properties........... 10,230 (10,643)(o) (413 )
Other revenues, net.... 936 249(n) 1,185
------- ------- ------- ------- -------- ------ --------
Total revenues... 81,934 (19,844) 7,513 2,886 (6,479) 66,010
------- ------- ------- ------- -------- ------ --------
COSTS AND EXPENSES:
Production and
operating............ 24,515 (3,642)(n) 662(f) 1,265(h) (3,423)(j) 19,377
Depreciation, depletion
and amortization..... 30,726 (2,853)(n) 3,506(f) 1,376(h) (1,846)(j) 30,909
General and
administrative....... 7,472 56(n) 7,528
Taxes other than
income............... 5,760 (243)(n) (561)(j) 4,956
Exploration............ 4,826 4,826
Impairment............. 1,822 1,822
------- ------- ------- ------- -------- ------ --------
Total costs and
expenses....... 75,121 (6,682) 4,168 2,641 (5,830) 69,418
------- ------- ------- ------- -------- ------ --------
INCOME (LOSS) FROM
OPERATIONS............. 6,813 (13,162) 3,345 245 (649) (3,408 )
Interest and other
expense, net........... (5,336) 3,013(p) (1,120)(g) (3,140)(i) 691(k) $3,207(l) (2,685 )
------- ------- ------- ------- -------- ------ --------
INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM..... 1,477 (10,149) 2,225 (2,895) 42 3,207 (6,093 )
Preferred stock
dividends.............. (1,800) (1,800 )
------- ------- ------- ------- -------- ------ --------
INCOME (LOSS) TO COMMON
STOCK BEFORE
EXTRAORDINARY ITEM..... $ (323) $(10,149) $ 2,225 $(2,895) $ 42 $3,207 $ (7,893 )
======= ======= ======= ======= ======== ====== ========
LOSS BEFORE EXTRAORDINARY
ITEM PER COMMON SHARE:
Primary and fully
diluted.............. $ (0.03) $ (0.52 )
======= ========
NUMBER OF COMMON AND
EQUIVALENT SHARES:
Primary and fully
diluted.............. 11,812 3,348(m) 15,160
======= ====== ========
</TABLE>

20
<PAGE> 21

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(1) BASIS OF PRESENTATION

The Pro Forma Condensed Consolidated Balance Sheet is presented as if the
expected sale of certain assets acquired in the September 1996 Acquisition, the
1996 Sales and the Offering occurred as of September 30, 1996. The Pro Forma
Condensed Consolidated Statements of Operations for the nine months
ended September 30, 1996 and for the year ended December 31, 1995 are presented
as if the 1995 Transactions, the March 1996 Acquisition, the September 1996
Acquisition and the expected sale of certain assets acquired therein, the 1996
Sales and the Offering were consummated as of January 1, 1995.

The September 1996 Acquisition, the March 1996 Acquisition and the portion
of the APPL Consolidation completed in 1995 have been accounted for in the Pro
Forma Statements using the purchase method of accounting. The value of the
interests acquired in the September 1996 Acquisition and the March 1996
Acquisition represents the cash consideration given to the seller. The total
value of the acquired interests in the APPL Consolidation was determined based
upon the fair value of the Common Stock and cash offered to the investors.

(2) LOSS PER COMMON SHARE

Loss per common share has been calculated by dividing net loss before
extraordinary items by the number of common shares outstanding at the end of the
respective period. Pro forma common shares outstanding includes the 3,347,826
shares of Common Stock to be issued by the Company in connection with the
Offering.

(3) PRO FORMA ADJUSTMENTS

Balance Sheet

(a) To eliminate the assets to be sold in the 1996 Sales.

(b) To eliminate that portion of assets acquired in the September 1996
Acquisition that are expected to be sold to a third party.

(c) To reflect the application of the estimated net proceeds of $5.7 million
from the expected sale of a portion of the assets acquired in the September
1996 Acquisition to repay amounts outstanding under the Credit Agreement.

(d) To reflect the application of the estimated net proceeds of $8.6 million
from the 1996 Sales to repay amounts outstanding under the Credit
Agreement.

(e) To reflect the issuance of shares pursuant to the Offering and to reflect
the application of the estimated net proceeds of $40.1 million to repay
amounts outstanding under the Credit Agreement.

Statement of Operations

(f) To reflect the results of operations for properties acquired in the March
1996 Acquisition.

(g) To adjust historical interest expense to reflect the $14 million increase in
outstanding bank debt to fund the March 1996 Acquisition assuming an annual
interest rate of 8%, based on the Company's weighted
average interest rate on its bank borrowings.

(h) To reflect the results of operations for the Company's interest in the
properties acquired in the September 1996 Acquisition, net of certain
interests being sold to a third party.

(i) To adjust historical interest expense to reflect the $39.3 million net
increase in outstanding bank debt to fund the September 1996 Acquisition
(net of interests being sold to a third party) assuming an annual interest
rate of 8%, based on the Company's weighted average interest rate on its
bank borrowings.

21
<PAGE> 22

(j) To eliminate the results of operations related to the 1996 Sales.

(k) To adjust historical interest expense to reflect the application of the
estimated net proceeds of $8.6 million from the 1996 Sales to reduce
outstanding bank debt assuming an annual interest rate of 8%, based on the
Company's weighted average interest rate on its bank borrowings.

(l) To adjust historical interest expense to reflect the application of the
estimated net proceeds from the Offering of $40.1 million to reduce
outstanding bank debt assuming an annual interest rate of 8%, based on the
Company's weighted average interest rate on its bank borrowings.

(m) To reflect the issuance of 3,347,826 shares of Common Stock by the Company
in connection with the Offering.

(n) To reflect the impact of the 1995 Transactions on the Company's results of
operations.

(o) To eliminate the nonrecurring gain on the Sawyer Sale.

(p) To adjust historical interest expense to reflect the repayment of $62.5
million of outstanding bank debt using the proceeds from the Sawyer Sale
and assuming an annual interest rate of 8%, based on the Company's weighted
average interest rate on its bank borrowings.

22
<PAGE> 23

SELECTED FINANCIAL DATA

The following table sets forth selected historical financial data for the
Company as of and for each of the years in the five-year period ended December
31, 1995 and for each of the nine-month periods ended September 30, 1995 and
1996. The historical financial data was derived from the consolidated financial
statements of the Company. The data in the following table should be read in
conjunction with Management's Discussion and Analysis of Financial Condition and
Results of Operations and the Consolidated Financial Statements and related
Notes thereto appearing elsewhere herein.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------------------------------ -----------------
1991 1992 1993(1) 1994(2) 1995(2)(3) 1995 1996
-------- -------- -------- -------- ---------- ------- -------
(IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
SUMMARY OF OPERATIONS DATA:
Revenues:
Oil and gas sales.......................... $ 71,499 $ 58,560 $ 49,589 $ 50,033 $ 70,768 $55,049 $52,263
Gain (loss) on sales of oil and gas
properties............................... (6,207) (1,309) (6,894) 1,110 10,230 9,674 801
Gas settlement income...................... 1,481 1,849 15,592 374 895 879 --
Other revenues, net........................ 3,268 908 (129) (158) 41 (201) 111
-------- -------- -------- -------- -------- ------- -------
Total revenues......................... 70,041 60,008 58,158 51,359 81,934 65,401 53,175
-------- -------- -------- -------- -------- ------- -------
Costs and Expenses:
Production and operating................... 22,836 19,412 15,998 21,302 24,515 19,079 15,421
Depreciation, depletion and amortization... 35,163 30,193 23,635 29,616 30,726 22,446 20,871
General and administrative................. 12,554 11,047 7,413 10,035 7,472 4,683 4,450
Taxes other than income.................... 6,799 5,606 4,601 5,710 5,760 4,413 4,254
Exploration................................ 5,687 7,843 7,554 2,559 4,826 3,269 9,152
Impairment................................. 340 45,586 10,975 33,570 1,822 43 1,841
-------- -------- -------- -------- -------- ------- -------
Total costs and expenses............... 83,379 119,687 70,176 102,792 75,121 53,933 55,989
-------- -------- -------- -------- -------- ------- -------
Income (loss) from operations................ (13,338) (59,679) (12,018) (51,433) 6,813 11,468 (2,814)
Interest expense............................. (11,997) (9,485) (6,847) (6,638) (5,481) (4,853) (2,894)
Other income (expense), net.................. 1,078 265 (321) (2,164) 145 (105) (63)
-------- -------- -------- -------- -------- ------- -------
Income (loss) before extraordinary item...... (24,257) (68,899) (19,186) (60,235) 1,477 6,510 (5,771)
Extraordinary gain on debt extinguishment.... -- 3,100 -- 5,419 2,456 2,456 --
-------- -------- -------- -------- -------- ------- -------
Net income (loss)...................... (24,257) (65,799) (19,186) (54,816) 3,933 8,966 (5,771)
Preferred stock dividends and expenses....... (114) -- (75) (1,800) (1,800) (1,350) (1,350)
-------- -------- -------- -------- -------- ------- -------
Net income (loss) to common stock...... $(24,371) $(65,799) $(19,261) $(56,616) $ 2,133 $ 7,616 $(7,121)
======== ======== ======== ======== ======== ======= =======
Net income (loss) per common share:
Primary and fully diluted:
Loss before extraordinary item......... $ (4.50) $ (10.73) $ (2.77) $ (7.70) $ (0.03) $ 0.43 $ (0.60)
Net income (loss)...................... (4.50) (10.25) (2.77) (7.02) 0.18 0.64 (0.60)
Cash dividends declared per common share..... -- -- -- -- -- -- --
OTHER FINANCIAL DATA:
EBITDA(4).................................... $ 32,448 $ 24,676 $ 37,224 $ 10,583 $ 33,981 $27,493 $28,186
Operating cash flow(5)....................... 18,875 13,136 26,813 4,838 27,514 21,714 24,285
Total capital expenditures(6)................ 63,636 22,516 24,167 49,889 44,215 31,229 92,116
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------- SEPTEMBER 30,
1991 1992 1993 1994 1995 1996
-------- -------- -------- -------- -------- -------------
<S> <C> <C> <C> <C> <C> <C>
SUMMARY OF BALANCE SHEET DATA:
Working capital (deficit)..................... $(27,066) $ 2,722 $(10,123) $ (4,102) $(11,691) $ (1,623)
Total assets.................................. 336,803 256,820 185,598 223,894 176,030 233,363
Long-term obligations and convertible
redeemable preferred stock excluding current
obligations................................. 135,226 115,256 62,848 100,710 40,000 105,000
Total stockholders' equity.................... 127,433 85,160 86,406 87,710 94,480 87,506
</TABLE>

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

(2) The Company purchased investors' interests in the APPL Programs in 1994 and
1995 for 4.6 million shares of Common Stock and $40.1 million in cash.

(3) The Company sold its interest in the Sawyer Field for $64 million in July
1995.

(5) Cash flow from operations before working capital changes and after preferred
dividends.

(6) Excludes the acquisition of properties in exchange for the issuance of
Common Stock, principally relating to the APPL Consolidation.

23
<PAGE> 24

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

Over the past four years, the Company has implemented a series of steps
that has resulted in a significant improvement in its oil and gas operating and
exploration capabilities, overhead and production costs, financial position and
cash operating margins. These steps include (i) hiring experienced personnel in
key management and operating positions, (ii) focusing exploration and
development activities in areas in which the Company has competitive advantages,
(iii) acquiring properties held by the APPL Programs and (iv) disposing of over
250 properties, including the sale of the Company's interest in the Sawyer Field
in West Texas for $64 million in July 1995. Largely as a result of these steps,
the Company's operating margin has increased from $2.72 per BOE for the year
ended December 31, 1992 to $6.02 per BOE for the nine months ended September 30,
1996. In addition, the Company's ratio of total debt to total capitalization has
decreased from 60% at December 31, 1992 to 28% on a pro forma basis at September
30, 1996.

The Company accounts for its oil and gas exploration and production
activities using the successful efforts method of accounting. Under this method,
acquisition costs for proved and unproved properties are capitalized when
incurred. Exploration costs other than drilling costs for successful wells,
including geological and geophysical costs and costs of carrying and retaining
unproved properties, are charged to expense as incurred. The costs of drilling
exploratory wells are capitalized pending determination of whether each well
resulted in the discovery of proved reserves. If proved reserves are not
discovered, such drilling costs are charged to expense. Costs incurred to drill
and equip development wells, including unsuccessful development wells, are
capitalized. Internal costs related to the acquisition, development and
exploration of oil and gas properties are expensed as incurred. Interest is
capitalized on qualifying assets, primarily unproved and unevaluated properties.

Depletion of the cost of producing oil and gas properties is computed on
the unit-of-production method. The Company also accrues for platform abandonment
costs related to its offshore platform facilities on the unit-of-production
method. Unproved properties are assessed periodically, and any impairment in
value is recognized currently as impairment expense.

QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED TO QUARTER AND NINE
MONTHS ENDED SEPTEMBER 30, 1995

Revenues. The Company recorded oil and gas sales of $19.1 million for the
third quarter of 1996 compared to $16.9 million for the third quarter of 1995.
Higher sales for the third quarter of 1996 primarily reflect a 12% increase in
the Company's average gas price and increased oil production relative to the
third quarter of 1995. For the first nine months of the year, oil and gas sales
totaled $52.3 million in 1996 and $55 million in 1995. The decline in sales for
the nine-month period of 1996, compared to the same period of 1995, is mainly
attributable to the Sawyer Sale, offset in part by higher gas prices and
increased oil production.

Gas production for the third quarter of 1996 totaled 5,942 MMcf,
representing a 1% decline from third quarter 1995 production of 6,013 MMcf. Gas
production from the properties acquired in the March 1996 Acquisition, together
with higher production due to successful development activity at High Island
Block 13-L and the Bradshaw Field, more than offset the decrease of
approximately 700 MMcf of July 1995 production from the Sawyer Field included in
the third quarter 1995 results. For the nine months ended September 30, 1996,
gas production totaled 15,772 MMcf compared to 19,866 MMcf for the same period
of 1995. The production decline for the nine-month period reflected the loss of
production of approximately 20 MMcf per day due to the Sawyer Sale. For the
quarterly and nine-month periods, the decline in gas volumes in 1996 negatively
impacted sales by approximately $100,000 and approximately $6.9 million,
respectively.

Oil production for the third quarter of 1996 increased to 453 MBbls from
403 MBbls for the third quarter of 1995 primarily due to additional volumes
related to the March 1996 Acquisition. On a nine-month basis, oil production
increased to a lesser extent, totaling 1,340 MBbls for 1996, or 7% above the
same period of 1995. Production increases during the first nine months of 1996
resulting from the March 1996 Acquisition, the late 1995 acquisition of an
additional interest in the Buckner Field and the successful 1995 drilling
program at the Midway Field were partially offset by the impact of the sales of
several oil producing properties in late 1995

24
<PAGE> 25
and early 1996. Increased oil production contributed approximately $800,000 to
the Company's third quarter revenues in 1996 and approximately $1.4 million to
nine-month 1996 revenues.

The Company's 1996 revenues were favorably impacted by approximately $1.5
million due to the effect of higher oil and gas prices in the third quarter of
1996 and by approximately $2.8 million due to higher gas prices for the first
nine months of 1996, compared to the respective periods of 1995. The Company's
gas price averaged $1.90 per Mcf and $1.88 per Mcf for the quarterly and
nine-month periods of 1996, respectively, compared to $1.69 per Mcf for the
third quarter of 1995 and $1.70 per Mcf for the first nine months of 1995. The
Company's average oil price increased by 3% for the quarterly period, rising to
$17.20 per Bbl in the third quarter of 1996 from $16.64 per Bbl for the same
period of 1995. For the first nine months of the year, the Company recorded an
average oil price of $16.87 per Bbl in both 1996 and 1995.

During the third quarter of 1996, the Company had in effect commodity price
swap agreements covering approximately 36% of the Company's gas production and
approximately 69% of its oil production. As a result of the price hedges, the
Company's oil and gas sales revenues were reduced by approximately $2.3 million
during the third quarter of 1996 and were increased by approximately $1.4
million during the same period of 1995. Excluding the impact of the hedging
gains and losses, the Company's average oil and gas prices for the third quarter
of 1996 would have been $20.47 per Bbl and $2.04 per Mcf. For the third quarter
of 1995, the Company's average prices exclusive of the hedges would have been
$15.93 per Bbl and $1.51 per Mcf.

For the first nine months of 1996, hedging agreements covered approximately
52% of the Company's gas production and approximately 67% of its oil production,
resulting in a revenue reduction of approximately $6.1 million. The Company's
nine-month 1996 oil and gas prices would have averaged $19.39 per Bbl and $2.05
per Mcf, exclusive of the hedges. For the comparable period of 1995, the Company
recorded a net hedging gain of approximately $2 million. The Company's average
gas price for the first nine months of 1995 was increased by $0.10 per Mcf due
to the hedges while the average oil price was reduced by $0.07 per Bbl.

In September 1996, the Company entered into additional commodity price swap
agreements covering 3,000 barrels of daily oil production for the period from
January 1, 1997 through December 31, 1997 at an average fixed price of $19.48
per Bbl. For information regarding oil and gas price hedging arrangements in
effect for the remainder of 1996, see "-- Hedging Activity" below.

During the third quarter of 1995, the Company reported a gain on the Sawyer
Sale of approximately $10 million. Also in 1995, other revenues for the
nine-month period included $879,000 of net gas settlement income as a result of
the final judgment in certain litigation regarding the terms of a gas purchase
contract.

Costs and Expenses. Production and operating costs totaled $5.2 million, or
$3.62 per BOE, for the third quarter of 1996 and $5.6 million, or $3.95 per BOE,
for the third quarter of 1995. The 6% decrease in production costs resulted from
reduced production in the third quarter of 1996 while the decline in the
Company's operating cost per unit of production was mainly attributable to the
impact of the offshore properties acquired in the March 1996 Acquisition. Such
properties have high production volumes and low operating costs relative to the
Company's onshore properties. For the nine-month period, production and
operating costs decreased to $15.4 million, or $3.89 per BOE, in 1996 from $19.1
million, or $4.18 per BOE, in 1995. The reduction in total costs was primarily
attributable to the Sawyer Sale, while lower unit costs mainly reflected the
impact of the March 1996 Acquisition.

Depreciation, depletion and amortization ("DD&A") totaled $7.4 million and
$6.9 million for the third quarter of 1996 and 1995, respectively. The increase
in DD&A for the quarterly periods primarily reflected the higher depletion rates
associated with platform abandonment costs for the offshore properties in the
Gulf of Mexico, which represent a greater portion of the Company's property base
than in 1995. For the nine-month period, DD&A totaled $20.9 million in 1996 and
$22.4 million in 1995. DD&A for the nine-month period declined in 1996 due to
lower gas production volumes resulting from the Sawyer Sale, with that decline
partially offset by the impact of higher depletion rates on the offshore
properties.

General and administrative ("G&A") expense declined to $1.3 million for the
third quarter of 1996 from $1.7 million for the same period of 1995. The
reduction in G&A expense reflected lower legal fees in 1996 as the 1995 quarter
included certain costs to resolve a dispute involving a well owned by one of the
NYLOG

25
<PAGE> 26

Programs. For the first nine months of 1996, G&A expense totaled $4.5 million
compared to $4.7 million for the same period of 1995.

Taxes other than income totaled $1.6 million and $1.3 million for the third
quarter of 1996 and 1995, respectively. Production tax expense for the 1995
quarter was unusually low due to the impact of certain severance tax refunds
received related to an outside operated property. During the first nine months
of the year, taxes other than income totaled $4.3 million in 1996 and $4.4
million in 1995. On a nine-month basis, the reduction in production taxes in
1996 due to the Sawyer Sale was essentially offset by the impact of the
severance tax refunds received in 1995, as mentioned above, and higher ad
valorem taxes in 1996.

Exploration expense totaled $2 million and $3.1 million for the third
quarter of 1996 and 1995, respectively, and totaled $9.2 million and $3.3
million for the first nine months of 1996 and 1995, respectively. The Company
began to shift its focus towards exploration activity in late 1995. For the
nine-month 1996 period, exploration expense included the costs of eleven
unsuccessful exploratory wells that were primarily offshore in the Gulf of
Mexico. Impairment expense of $1.8 million in the third quarter of 1996 related
to the write-off of unproved properties on which no further exploration or
development activity is planned.

Interest expense for the third quarter of 1996 totaled $1.1 million
compared to $1 million for the same period of 1995. In addition to interest on
the Subordinated Notes, interest expense for the 1996 quarter related to the
Company's average outstanding bank debt of approximately $25 million for
substantially all of the third quarter of 1996 (since the $45 million funding of
the September 1996 Acquisition occurred near the end of the quarter) while such
expense for the 1995 quarter was primarily based on a $62.5 million bank debt
balance that was outstanding for only one month of the quarter before being
eliminated by the application of the proceeds from the Sawyer Sale. For the
first nine months of 1996, interest expense of $2.9 million was 40% below the
same period in 1995 reflecting higher bank debt carried in the first half of
1995 following the completion of the APPL Consolidation.

Extraordinary Item. The $2.5 million extraordinary gain recorded in 1995
resulted from the extinguishment of nonrecourse debt in conjunction with the
APPL Consolidation.

Net Income (Loss). The Company reported a net loss of $1.2 million and $5.8
million for the third quarter and first nine months of 1996, respectively,
compared to net income of $6 million for the third quarter of 1995 and net
income of $9 million for the nine-month period of 1995. Net losses during 1996
were attributable to an aggregate charge of $3.8 million for exploration and
impairment expenses for the third quarter and $11 million of such expenses for
the first nine months of the year. In 1995, net income for both periods included
the impact of an approximate $10 million gain on the Sawyer Sale, and nine-month
1995 income also reflected a $2.5 million extraordinary gain on debt
extinguishment.

1995 COMPARED TO 1994

Revenues. Oil and gas sales totaled $70.8 million in 1995, 41% higher than
1994 sales of $50.0 million. The increase in 1995 sales revenues primarily
reflects higher production volumes which resulted from the APPL Consolidation.
Through the APPL Consolidation, the Company acquired 22.9 MMBOE and 2.3 MMBOE of
proved oil and gas reserves in late 1994 and early 1995, respectively. The APPL
Consolidation, together with successful development activity at the Midway and
West McAllen fields and the West Cameron Block 408, resulted in a net production
increase of 1.8 MMBOE in 1995 compared to 1994. The higher production levels
achieved through the APPL Consolidation were partially offset by the loss of
production due to the Sawyer Sale in July 1995. The Company's total oil and gas
production increased to 5.8 MMBOE in 1995 from 3.9 MMBOE in 1994, contributing
$22.3 million to oil and gas sales.

Oil and gas sales reflect the impact of lower gas prices offset by higher
oil prices received in 1995. The Company realized an average price of $16.83 per
Bbl of oil in 1995 compared to $15.39 in 1994, which resulted in a $2.4 million
addition to sales revenues. The Company's average gas price realization declined
to $1.74 per Mcf in 1995, or 8% below the prior year average. The decline in the
average gas price negatively impacted sales revenues by $3.9 million.

In July 1995, the Company sold its interest in the Sawyer Field to Louis
Dreyfus Natural Gas Corp. for a purchase price of $64.0 million. The Company
recorded a gain on the sale of the Sawyer Field of

26
<PAGE> 27

approximately $10.6 million in 1995. Sales of various other fields in 1995
resulted in a net loss on those fields of approximately $400,000. In 1994, the
Company recognized a $1.1 million gain on the divestiture of minor properties.

Other revenues totaled $936,000 and $216,000 in 1995 and 1994,
respectively. In 1995, the Company recorded gas settlement income of $895,000,
primarily consisting of the proceeds from certain litigation regarding the terms
of a gas purchase contract. The Company also recognized approximately $480,000
of gas balancing income during 1995, primarily relating to cash balancing
settlements receivable on various wells which were plugged and abandoned during
1995. During December 1995, the Company accrued $700,000 as a reduction of other
revenues due to the loss of correlation between actual cash prices and the
prices under the swap agreements at the Henry Hub market reference price. Other
revenues recorded in 1994 primarily included gas balancing income.

Costs and Expenses. Production and operating costs increased to $24.5
million in 1995 from $21.3 million in 1994. The increase in 1995 costs was
mainly attributable to higher production levels resulting from the APPL
Consolidation, although that increase was mitigated by a reduction in
environmental expenses in 1995. During 1994, the Company incurred $2.4 million
of site remediation costs in connection with various environmental proceedings.
On a unit cost basis, production and operating costs per BOE decreased to $4.26
per BOE in 1995 from $5.40 per BOE in 1994, reflecting continued operating
efficiencies achieved following the completion of the APPL Consolidation.

DD&A totaled $30.7 million in 1995 or 4% over 1994 DD&A of $29.6 million.
The Company's DD&A per BOE rate decreased substantially during 1995;
consequently, the Company's DD&A expense did not increase proportionately with
the 46% production increase in 1995. DD&A per BOE decreased to $5.34 per BOE in
1995 from $7.50 per BOE in 1994. The lower DD&A rate reflects the effect of the
acquisition of interests through the APPL Consolidation and the impact of a
$25.0 million impairment charge recorded in the fourth quarter of 1994, which
reduced the cost basis of certain oil and gas properties.

G&A declined to $7.5 million in 1995 from $10.0 million in 1994. The
reduction in G&A resulted primarily from staff reductions in the first half of
1994 and a $2.0 million severance charge recorded in late 1994 in connection
with the elimination of certain partnerships managed by the Company. These
decreases have been partially offset by the loss of management and technical fee
reimbursements previously received from the APPL Programs. The Company's
continuing focus on controlling administrative costs resulted in a 49% reduction
in G&A per unit of production during 1995, which averaged $1.30 per BOE in 1995
compared to $2.54 per BOE in 1994.

Taxes other than income taxes were relatively constant, totaling $5.8
million in 1995 and $5.7 million in 1994. The Company's production tax rate in
1995 was reduced due to the receipt of certain severance tax refunds related to
an outside operated property.

Exploration expense totaled $4.8 million and $2.6 million in 1995 and 1994,
respectively. The Company recognized $4.1 million of dry hole expense on three
wells in 1995, including two offshore wells, compared to $1.5 million of dry
hole expense related to three unsuccessful wells drilled in 1994.

The Company recorded $1.8 million of impairment expense in 1995 compared to
a $33.6 million charge in 1994. The 1995 impairment relates primarily to the
fourth quarter write-off of an unproved offshore property. As discussed below
under the caption "-- 1994 Compared to 1993," the Company recorded a $25.0
million impairment charge in 1994 related to a change in accounting policy and a
$6.4 million charge to write off the Company's remaining leasehold interest in
Tunisia.

Interest expense of $5.5 million in 1995 was 17% below 1994 expense of $6.6
million primarily due to the repayment of $62.5 million of bank debt using the
proceeds of the Sawyer Sale in July 1995. In addition, the Company has
extinguished certain nonrecourse debt associated with the APPL Programs totaling
$6.6 million and $13.6 million in 1995 and 1994, respectively. Other expense of
$2.6 million in 1994 included $2.1 million of fees paid by the Company in
connection with a new bank credit agreement and a bridge facility with New York
Life.

27
<PAGE> 28

Extraordinary Item. The Company recorded extraordinary gains of $2.5
million in 1995 and $5.4 million in 1994 related to the elimination of
nonrecourse debt in conjunction with the APPL Consolidation. The gain
represented the difference between the outstanding note balances and the actual
purchase price of the notes.

Net Income (Loss). The Company reported net income of $3.9 million, or
$0.18 per share, in 1995 and a net loss of $54.8 million, or $7.02 per share, in
1994. Nonrecurring transactions reflected in 1995 net income include a $10.2
million gain on property sales, primarily the Sawyer Sale, a $2.5 million
extraordinary gain on the extinguishment of debt and $895,000 of gas settlement
income, partially negated by a $1.8 million impairment charge and a $700,000
loss related to certain natural gas hedges. In contrast, 1994 results included
the negative impact of a $33.6 million impairment charge partially offset by a
$5.4 million extraordinary gain and a $1.1 million gain on property sales.
Excluding the effect of these nonrecurring transactions in both years, the
Company would have recorded net losses of $7.2 million and $27.7 million in 1995
and 1994, respectively. The improvement in operating results primarily reflects
a $17.5 million increase in net operating revenues, which resulted from higher
production levels and reduced unit operating costs following the APPL
Consolidation. In addition, reductions in G&A and interest expense in 1995 more
than offset higher DD&A and exploration expense recorded in that year.

1994 COMPARED TO 1993

Revenues. Oil and gas sales in 1994 totaled $50.0 million compared to $49.6
million in 1993. The Company's 1994 sales reflected higher domestic oil and gas
production offset in part by the impact of declining prices and the sales of the
Company's Canadian oil and gas properties in mid-1993. Comparing the Company's
total production for the two years, the combined effect of a 6% increase in gas
production and a 2% decline in oil production resulted in a net increase to
sales of $1.4 million. Excluding the 1993 Canadian production, which totaled 662
MBOE, the Company's oil and gas production increased by 793 MBOE as a result of
the drilling of new development wells, workovers and recompletions of existing
wells in the first half of the year and the acquisition of investors' interests
in the APPL Programs primarily during the second half of 1994. For 1994, the
Company's average realized natural gas and oil prices were down 1% and 4%,
respectively, from 1993, decreasing sales by $1.0 million. The Company's
realized prices include the impact of certain hedging arrangements relating to a
portion of its natural gas and oil production during 1994. As a result of these
hedges, natural gas sales increased by $1.6 million and oil revenues were
reduced by $44,000.

The Company recognized a gain on sales of oil and gas properties of $1.1
million in 1994 compared to a loss on property sales of $6.9 million in 1993. In
mid-1993, the sale of the Company's Canadian assets resulted in losses totaling
$5.8 million, including $1.8 million for the elimination of the accumulated
foreign currency translation adjustment. The gain for 1994 and the remaining
loss for 1993 resulted from the divestiture of minor properties.

The Company recorded gas settlement income of $15.6 million in 1993, which
included amounts received in connection with the settlement of certain
litigation regarding the terms of a gas purchase contract and for the
renegotiation of the Company's contract to sell gas from the Thomasville Field.
These amounts are reflected as other revenues on the accompanying statements of
operations.

Costs and Expenses. Production and operating expenses increased 33% to
$21.3 million in 1994. The Company's operating costs were increased by $3.8
million during the second half of 1994 due to the acquisition of interests
pursuant to the APPL Consolidation. In addition, the Company recorded site
remediation costs of $2.4 million in 1994. On a BOE basis, operating costs
increased 29% to $5.40 in 1994 compared to $4.19 in 1993. These increases
reflected higher U.S. operating costs which more than offset the decreases
associated with the sales of the Company's Canadian properties in mid-1993.
Higher domestic operating expenses were related to workovers at the Brazos
Blocks and the Sawyer Field totaling $1.1 million.

DD&A expense totaled $29.6 million in 1994, with the 25% increase from the
prior year attributable to an increase in the Company's DD&A per BOE rate and
higher gas production. Downward reserve revisions at year-end 1993, including
reserve revisions related to low oil prices at year-end 1993, resulted in a DD&A
per BOE rate of $7.50 in 1994 compared to $6.19 in 1993. The higher 1994 rate is
also due to the fact that the

28
<PAGE> 29

Canadian properties sold in mid-1993 had a lower depletion rate than the average
rate for the Company's other properties.

G&A totaled $10.0 million in 1994, or 35% above 1993 expense of $7.4
million. The higher G&A for 1994 primarily related to the loss of management and
technical fee reimbursements as a result of the APPL Consolidation with no
significant reductions in G&A in 1994. As a result of planned reductions related
to the elimination of certain partnerships managed by the Company, the Company
recorded a $2.0 million severance charge in 1994. These increases were partially
offset by a decrease in salaries and benefits associated with the reductions in
the Company's work staff in early 1994 and the elimination of Canadian G&A.

Taxes other than income increased by $1.1 million in 1994 compared to 1993,
due primarily to higher production taxes related to increased domestic oil and
gas sales and higher ad valorem taxes related to an increase in the Company's
oil and gas property base due to the APPL Consolidation.

Exploration expense decreased 66% to $2.6 million in 1994. The decrease in
exploration expense reflected steps taken by the Company to eliminate its
international exploration commitments and to emphasize domestic development and
exploitation projects in 1994.

The Company recorded impairment charges totaling $33.6 million in 1994 and
$11.0 million in 1993. Effective December 31, 1994, the Company changed its
accounting policy related to impairment of proved oil and gas properties to a
policy that is consistent with the provisions of the Financial Accounting
Standards Board ("FASB") exposure draft, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." A final
statement was subsequently issued by the FASB in March 1995. Previously, the
Company's impairment policy was to recognize an impairment of proved oil and gas
property costs if, on a company-wide basis, those costs exceeded the
undiscounted after-tax future net cash flows from proved reserves. Under the
policy adopted by the Company, if the book value of an individual proved field
is greater than its undiscounted future net cash flow from proved reserves, then
an impairment is recognized for the difference between the net book value and
the fair value. Management's initiative to change its policy was prompted by the
considerable volatility of oil and gas prices during the past several years, the
resulting economic losses of proved reserves and corresponding increases in the
Company's DD&A rate. This change in accounting policy resulted in a $25.0
million noncash impairment charge for 1994 against the book value of certain of
the Company's proved oil and gas properties.

Impairment expense for 1994 also included a $6.4 million noncash charge for
the write-off of the Company's remaining leasehold interest in Tunisia. The
Company sold its interest in exchange for the purchaser assuming its remaining
Tunisian commitment. The remaining impairment expense for 1994 primarily
represented the write-off of several domestic prospects on which the Company did
not plan to conduct any further exploratory activity. The impairment charge for
1993 included $10.2 million associated with the write-offs of the Company's
leasehold interest in Oman and a portion of the leasehold interest in Tunisia.

Interest expense decreased 3% in 1994 to $6.6 million due primarily to a
lower average bank debt balance during 1994 and the elimination of $14.1 million
of debt in connection with the Canadian asset sales in mid-1993, offset in part
by a decrease in capitalized interest. Capitalized interest decreased to $1.5
million in 1994 from $2.3 million in 1993 due to a reduction in the unproved
property base for interest capitalization. Other expense of $2.6 million in 1994
included $2.1 million of fees paid by the Company in connection with a new bank
credit agreement and the bridge facility extended to the Company by New York
Life for the APPL Consolidation.

Extraordinary Item. As part of the APPL Consolidation, the Company recorded
a $5.4 million extraordinary gain in 1994 resulting from the elimination of
nonrecourse debt in conjunction with the repurchases of notes issued by, and net
profits interests in, certain of the APPL Programs.

Net Loss. The Company reported a net loss of $54.8 million, or $7.02 per
share, in 1994 compared to a net loss of $19.2 million, or $2.77 per share, in
1993. The higher net loss for 1994 was primarily due to the impact of the
impairment of proved properties, an increase in operating costs and expenses on
a per unit of production basis and the gas settlement income received in 1993,
offset in part by lower exploration expense

29
<PAGE> 30

and the extraordinary gain in 1994 as well as the loss on the sales of the
Company's Canadian assets recognized in 1993.

CAPITAL RESOURCES AND LIQUIDITY

The Company's principal sources of capital are net cash provided by
operating activities and proceeds from financing activities. During the last
three years, the Company has also generated substantial cash flows from the sale
of oil and gas properties, most notably the Sawyer Sale. The Company's primary
uses of capital are to fund its development and exploration programs and
acquisition activity. The Company also has financial obligations related to its
Convertible Preferred Stock and Subordinated Notes.

Net cash provided by operating activities totaled $27.1 million during the
first nine months of 1996 compared to $23.7 million during the same period of
1995. The improvement in operating cash flows was attributable to a higher
operating margin per unit of production in 1996 resulting from higher gas
prices, reduced production and operating costs and lower interest expense.

Net cash provided by operating activities increased to $33.3 million in
1995, as compared to the 1994 amount of $7.7 million. The improvement in cash
flow reflected the impact of the APPL Consolidation and successful development
activity, which together resulted in a 46% increase in production in 1995
compared to 1994. In addition, the Company's operating margins increased in 1995
as unit costs for production, G&A and interest expense decreased in 1995.
Operating cash flow in 1995 also reflected a $5.8 million positive working
capital adjustment which reflects an increase in accounts payable due to the
timing of certain payments. Net cash provided by operating activities totaled
$24.7 million in 1993 which included $15.6 million of gas settlement income
received in that year.

As of September 30, 1996, the borrowing base under the Credit Agreement was
$90 million, reflecting the increase in the aggregate value of the Company's oil
and gas properties due to the March 1996 Acquisition and the September 1996
Acquisition. Upon completion of the Offering and application of the estimated
net proceeds, the Company anticipates that the amount outstanding under the
Credit Agreement will be approximately $15.5 million and the borrowing base will
be approximately $75 million. The borrowing base is scheduled to be redetermined
semiannually every March and September.

The Credit Agreement and the Subordinated Notes require the Company to
comply with certain covenants including, but not limited to, restrictions on
indebtedness, investments, payment of dividends and lease commitments and a
requirement to maintain a minimum net worth of $64.6 million. Cash dividends are
restricted on the Common Stock, and preferred dividends are limited to $2
million in any one year. In addition, these agreements contain cross-default
provisions.

Proceeds from the sale of oil and gas properties, net of post-closing
adjustments, totaled $63.5 million, $2.6 million and $35.7 million in 1995, 1994
and 1993, respectively. Property sales in 1995 primarily included the Sawyer
Sale with proceeds of $64 million, as well as other minor properties. The
significant reduction of the Company's bank debt as a result of such sales
strengthened the Company's financial position. Divestitures in 1994 were
comprised of non-strategic, low-value properties while the most significant 1993
sales included the sale of the Company's Canadian assets and the conveyance of a
40% interest in the Henderson Canyon Field to certain investment programs
managed by the Company.

During the first nine months of 1996, capital expenditures for the
acquisition of oil and gas properties totaled $62.8 million, compared to $11.1
million for the same period of 1995. Through September 30, 1996, the Company
invested $53 million, net of interests being sold to a third party, to acquire
interests in seven blocks in the Gulf of Mexico, four of which are operated by
the Company. In aggregate, the March 1996 Acquisition and the September 1996
Acquisition added estimated proved reserves of approximately 4.2 MMBbls of oil
and 28.2 Bcf of natural gas (as estimated by the Company as of the date of each
acquisition). Other acquisition expenditures in 1996 primarily related to
leasehold additions in South Texas and the Gulf of Mexico. Acquisition
expenditures in 1995 primarily related to the APPL Consolidation.

Capital expenditures for the cash acquisition of oil and gas properties
totaled $16.0 million, $28.4 million and $4.3 million in 1995, 1994 and 1993,
respectively. Acquisition expenditures in 1995 included $9.0 million

30
<PAGE> 31

related to the APPL Consolidation, $2.4 million for certain interests in the
Buckner Field in Arkansas and the purchase of several offshore blocks in the
Gulf of Mexico. Acquisitions in 1994 primarily related to the APPL
Consolidation.

Development and exploration expenditures for the first nine months of 1996
and 1995 totaled $29.3 million and $20.1 million, respectively. Significant
development activity in 1996 included a successful well at High Island Block
13-L and eleven completions at the Bradshaw Field in Kansas. The Company is
conducting additional development activity in the Gulf of Mexico and in various
fields in South Texas. The Company participated in the completion of 16
exploratory wells during the first nine months of 1996, of which five wells were
successful, including four prospects in South Texas. Through September 1996, the
Company participated in 50 gross wells (18.7 net), with a success rate of
approximately 70%. The Company plans to invest approximately $15 million and to
drill over 20 wells during the fourth quarter of 1996. There can be no
assurances regarding the success of any wells drilled, and exploratory wells
involve greater risks than development wells. Under successful efforts
accounting, the costs incurred for the drilling of unsuccessful exploratory
wells are recorded as exploration expense and negatively impact net income in
the period in which incurred.

Development and exploration expenditures totaled $27.5 million in 1995
compared to $20.9 million and $18.7 million in 1994 and 1993, respectively.
Significant projects in 1995 included drilling in the Gulf of Mexico in the
Vermilion, West Cameron and Brazos blocks. The Company also conducted
development activity in several fields, including the Midway Field in Arkansas,
the West McAllen Field in South Texas and the Bradshaw Field in Kansas. The
Company drilled three unsuccessful exploratory wells in 1995, of which two were
offshore in the Gulf of Mexico.

The Company's capital commitments for 1996 totaled $8.1 million, including
$2.4 million for operating lease obligations, $1.8 million for preferred
dividends and $3.9 million for interest payments on the Subordinated Notes.
Under the terms of an amendment to the Credit Agreement dated October 15, 1996,
the Company is scheduled to begin the repayment of principal under the Credit
Agreement over ten quarterly installments commencing in September 1999.
Principal payments under the Credit Agreement had previously been scheduled to
begin in September 1997. In September 1996, holders of the Subordinated Notes
agreed to an extension of the principal payment dates of the notes, which were
scheduled to begin in December 1997, in exchange for a reduction in the exercise
price from $22.95 per share to $15.53 per share of warrants to purchase shares
of Common Stock that were issued to the holders of the notes contemporaneously
with the issuance of such notes. As a result of this extension, annual principal
payments of $11.7 million on the Subordinated Notes will begin in December 2002.

The Company's ratio of current assets to current liabilities was 0.67:1 at
the end of 1995 compared to 0.86:1 at year-end 1994. The Company historically
has operated with a working capital deficit primarily due to timing differences
between the receipt of reimbursements from other working interest owners in the
properties operated by the Company and the payment of expenses with respect to
such properties.

The Company expects its 1997 capital expenditures for development and
exploration activities to range from $50 million to $75 million depending on
various factors, including the level of exploration success and subsequent
development activity. Following the Offering, the Company intends to fund its
planned capital expenditures, commitments and working capital requirements
through cash flows from operations and borrowings under the Credit Agreement.
However, if there are changes in oil and gas prices, which correspondingly
affect cash flows and bank borrowings, or if additional development and
exploration opportunities arise, the Company may adjust its capital budget
accordingly. Other potential sources of capital for the Company include property
sales and financings through the issuance of debt or equity securities.
Management believes that the Company will have sufficient capital resources and
liquidity to fund its capital expenditures and meet its financial obligations as
they are due.

As a result of the Offering, the Company will be subject to revised
individual annual and cumulative net operating loss carryforward ("NOL") limits
for federal income tax purposes. Prior to the Offering, the Company's annual and
cumulative NOL limits totaled approximately $13.7 million and approximately
$76.3 million, respectively. Upon completion of the Offering, the Company's
annual and cumulative NOL

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<PAGE> 32

limits will each be approximately $10 million due to changes in the Company's
ownership over the last three years.

ENVIRONMENTAL MATTERS

The Company is subject to various federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to the protection of the environment, which have become
increasingly stringent. The Company has conducted a review of its operations
with particular attention to environmental compliance. The Company believes it
has acted as a prudent operator and is in substantial compliance with
environmental laws and regulations. The Company recorded site remediation costs
of $541,000 and $2.4 million in 1995 and 1994, respectively. The site
remediation costs incurred in 1994 primarily related to certain lawsuits. Prior
to 1994, the Company's cost to comply with environmental provisions was not
material. The Company cannot predict what impact environmental laws and
regulations will have on its future performance, but does not currently
anticipate material environmental expenditures. However, the Company believes
that such laws do not affect the Company in a materially different manner from
other similarly situated companies in the oil and gas industry.

As discussed in Note 14 to the Consolidated Financial Statements included
in this Prospectus, during 1995, the Company was a defendant in five lawsuits
alleging the presence of naturally occurring radioactive materials ("NORM") and
other hazardous substances as a result of oil and gas operations conducted on
properties operated or owned by the Company and its predecessors in title or as
a result of NORM-contaminated pipe delivered to a pipe cleaning facility, of
which the Company contributed a minor amount of pipe. Three of the lawsuits have
been dismissed. The Company has remediated several of these properties and
believes these remediation efforts will significantly reduce the basis for the
plaintiffs' damage claims. Although the Company cannot predict the outcome of
these proceedings, management does not expect the outcome of the two remaining
cases to have a material adverse impact on the Company's financial position or
results of operations.

HEDGING ACTIVITY

The Company's derivative financial instruments are used solely to manage
the risk associated with fluctuations in oil and gas prices. The following table
details the commodity price swap agreements in effect at September 30, 1996.

<TABLE>
<CAPTION>
AVERAGE MARKET PRICE
PRODUCT CONTRACT PERIOD DAILY PRODUCTION FIXED PRICE REFERENCE
- ------- ---------------------------- ---------------- ----------- --------------------
<S> <C> <C> <C> <C>
Gas June 1996 - May 1997 20,000 MMBtu $ 1.86 Houston Ship Channel
Gas June 1996 - May 1997 2,000 MMBtu 2.13 Henry Hub
Oil January 1996 - December 1996 1,000 barrels 17.00 NYMEX WTI
Oil April 1996 - March 1997 400 barrels 18.22 NYMEX WTI
Oil July 1996 - December 1996 2,000 barrels 17.80 NYMEX WTI
Oil January 1997 - December 1997 3,000 barrels 19.48 NYMEX WTI
</TABLE>

With regard to the production hedged under each commodity price swap
agreement, if the market price is above the fixed price, the Company will pay to
the counterparty the difference between the fixed price and the market price;
and if the market price is below the fixed price, the Company will receive that
difference from the counterparty. The Company is exposed to credit loss in the
event of nonperformance by the other party to each swap agreement. However, the
Company anticipates that the counterparty will be able to fully satisfy its
obligation under each agreement.

Additionally, the Company purchased put options for 2,000 MMbtu per day of
gas with an average floor price of $1.90 per MMbtu (based on the Tennessee Gas
Pipeline Co., Louisiana and Offshore reference price) for the period from April
1996 through April 1997.

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<PAGE> 33

BUSINESS

GENERAL

Over the past four years, the Company has implemented a series of steps
that has resulted in a significant improvement in its oil and gas operating and
exploration capabilities, overhead and production costs, financial position and
cash operating margins. These steps include (i) hiring experienced personnel in
key management and operating positions, (ii) focusing exploration and
development activities in areas in which the Company believes it has competitive
advantages, (iii) acquiring properties held by the APPL Programs and (iv)
disposing of over 250 properties, including the sale of the Company's interest
in the Sawyer Field in West Texas for $64 million in July 1995. Largely as a
result of these steps, the Company's operating margin has increased from $2.72
per BOE for the year ended December 31, 1992 to $6.02 per BOE for the nine
months ended September 30, 1996. In addition, the Company's ratio of total debt
to total capitalization has decreased from 60% at December 31, 1992 to 28% on a
pro forma basis at September 30, 1996.

BUSINESS STRATEGY

GEOGRAPHIC FOCUS. The Company's exploration, development and acquisition
activities are primarily focused in the Gulf of Mexico (with an emphasis on the
Texas State Waters area), South Texas (with an emphasis on the Wilcox Trend) and
the Smackover Trend in southwestern Arkansas. The Company believes that by
focusing its operations, it can achieve cost efficiencies and enhance its
ability to add new reserves. For 1996, over 90% of the Company's exploration and
development budget and all of its acquisition activities have been concentrated
in its core operating areas. The Company is also in the process of divesting
certain properties that are not consistent with its geographic focus (see
"Prospectus Summary -- Recent Developments and Results") and is reviewing the
feasibility of divesting various additional non-strategic properties.

ACTIVE DRILLING PROGRAM. The Company is engaged in an active drilling
program and attempts to maintain a project portfolio consisting of both high
risk, high potential exploration prospects and lower risk development projects.
The Company's exploration activities are generally concentrated in areas where
in-house geological knowledge and 2-D seismic data can be used to identify
prospect leads. The Company then attempts to establish large lease positions and
generally initiates or acquires 3-D seismic data to confirm prospects prior to
drilling. The Company typically shares the risks associated with its exploration
prospects with industry partners. In addition to internally generated
exploration prospects, the Company selectively participates in exploration
prospects initiated by other oil and gas companies. For 1996, the Company has
budgeted approximately $40 million for exploration and development and intends
to drill approximately 40 gross (17 net) exploratory wells and 45 gross (21 net)
development wells. Of the $40 million,

33
<PAGE> 34

approximately $20 million is budgeted for exploration activities and
approximately $20 million is budgeted for development activities. During the
first nine months of 1996, the Company spent approximately $18 million on
exploration and drilled 16 gross (7.0 net) wells, 31% of which were successfully
completed. During the same period, the Company spent approximately $12 million
on development and drilled 34 gross (11.7 net) wells, 85% of which were
successfully completed.

SELECTIVE ACQUISITIONS. The Company's acquisition strategy is to acquire
producing properties within its core operating areas that enhance its
competitive position, offer economies of scale and provide further development
and/or exploration potential. The Company seeks to acquire properties in which
it can obtain a significant ownership percentage and become the operator.
Through September 1996, the Company has invested $53 million, net of interests
being sold to a third party, to acquire interests in seven Gulf of Mexico
fields, four of which are operated by the Company. See "Prospectus
Summary -- Recent Developments" and the Pro Forma Condensed Consolidated
Financial Statements.

FINANCIAL FLEXIBILITY. The Company is committed to maintaining financial
flexibility in order to pursue its existing exploration and development projects
and to take advantage of future opportunities. The Company has taken a number of
steps over the past few years to reduce debt and improve its liquidity and
financial flexibility. As a result, the Company's ratio of total debt to EBITDA
(see Note 4 to "Prospectus Summary -- Summary Financial Data") for the prior 12
months decreased from 5.2 as of December 31, 1992 to 1.3 on a pro forma basis as
of September 30, 1996. The Company intends to use the net proceeds from the
Offering to reduce its outstanding bank debt. After giving effect to the
proceeds from the Offering, the Company's pro forma ratio of total debt to total
capitalization as of September 30, 1996 is expected to be 28%. See "Use of
Proceeds," "Capitalization" and the Pro Forma Condensed Consolidated Financial
Statements.

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<PAGE> 35

PRIMARY OPERATING AREAS

Set forth below is information concerning certain of the Company's most
significant fields on a pro forma basis.

<TABLE>
<CAPTION>
PRO FORMA AS OF JUNE 30, 1996
PRO FORMA --------------------------------------------------------------
AVERAGE DAILY PRESENT VALUE
PRODUCTION PROVED RESERVES OF ESTIMATED
AVERAGE DURING ----------------------------------------------- FUTURE NET
WORKING SEPTEMBER 1996 OIL GAS REVENUES
OPERATOR INTEREST (BOEPD) (MBBL) (MMCF) MBOE (IN THOUSANDS)
--------- ------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Gulf of Mexico
High Island Block 116..... Other 45% 3,100 250 16,678 3,030 $ 27,275
East Cameron Block 328.... AX 100% 400 3,626 2,236 3,999 21,832
High Island Block 45...... AX 21% 900 64 6,075 1,077 10,642
High Island Block 98-L.... Other 22% --(1) -- 4,671 779 3,886
Brazos Complex............ AX 50% 1,000 2 3,766 630 3,613
Other..................... AX/Other Varies 2,000 435 5,842 1,407 11,330
------ ------ ------- ------- --------
7,400 4,377 39,268 10,922 78,578
------ ------ ------- ------- --------
South Texas
AWP Field................. AX 51% 700 593 3,600 1,193 6,170
West McAllen Field........ AX 66% 500 1 2,371 396 2,982
Provident City Area....... Other Varies 400 37 1,788 335 2,808
Other..................... AX/Other Varies 500 467 2,074 813 5,249
------ ------ ------- ------- --------
2,100 1,098 9,833 2,737 17,209
------ ------ ------- ------- --------
Smackover Trend
Buckner Field............. AX 100% 200 1,541 -- 1,541 7,049
Midway Field.............. AX 64% 500 913 -- 913 4,061
Other..................... AX/Other Varies -- 29 260 73 846
------ ------ ------- ------- --------
700 2,483 260 2,527 11,956
------ ------ ------- ------- --------
Other
Bowdoin Field............. Other 17% 400 -- 15,407 2,568 21,168
Bradshaw Field............ AX 87% 2,100(2) -- 36,967 6,161 20,295
Henderson Canyon Area..... AX 34% 400 56 11,150 1,915 9,224
Other..................... AX/Other Varies 5,300 5,233 32,296 10,614 66,618
------ ------ ------- ------- --------
8,200 5,289 95,820 21,258 117,305
------ ------ ------- ------- --------
Total............. 18,400 13,247 145,181 37,444 $ 225,048
====== ====== ======= ======= ========
</TABLE>

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

(1) High Island Block 98-L is a 1996 discovery not yet placed on production.

(2) Based on 23 days of production as the Bradshaw Field was shut in for seven
days in September due to maintenance at the purchaser's gas plant.

GULF OF MEXICO

The Gulf of Mexico is the Company's most significant area of exploration,
development and acquisition activity and represents approximately 60% of the
Company's 1996 exploration and development budget. On a pro forma basis,
approximately 40% of total oil and gas production during September 1996 and
approximately 29% of the Company's total proved reserves as of June 30, 1996
were attributable to properties in the Gulf of Mexico. As of June 30, 1996, the
Company held working interests in 41 offshore blocks covering 76,515 gross
(28,788 net) undeveloped acres.

35
<PAGE> 36

A description of American Exploration's major Gulf of Mexico properties
follows.

High Island Block 116. High Island Block 116 is located in shallow federal
waters, offshore Texas. The Company acquired a 45% working interest in the block
in September 1996. The block was placed on production in August 1996 and for the
month of September 1996 was producing approximately 45,000 gross (17,000 net)
Mcf of gas and approximately 800 gross (300 net) barrels of oil per day from the
Lower Miocene sands at an approximate depth of 10,000 feet. The producing well
has three additional behind pipe intervals which are classified as proved.

East Cameron Block 328. East Cameron Block 328 is located in approximately
240 feet of water in federal waters, offshore Louisiana. The block is located on
the flank of a large salt feature with multiple sands located in several major
fault blocks. The Company acquired a 100% working interest in the block in
September 1996 and is the operator. Initial production on the block was
established in the Trim 'A' and 'S' sands in the early 1970s and in 1995, a
subsequent operator re-established production in the Trim 'A' sand and
discovered oil and gas in the HB-1 sand. The block is currently producing
approximately 500 gross (400 net) barrels of oil per day from two wells, one
each in the Trim 'A' and HB-5 sands. Over the next year, the Company plans to
complete a subsea discovery in the HB-1 sand and will drill several development
wells which offset existing production.

High Island Block 45. High Island Block 45 is located in shallow federal
waters, offshore Texas. The Company holds a 21% working interest in the block
and is the operator. The block was placed on production in March 1995 and during
September 1996 produced approximately 4,800 net Mcf of gas and 53 net Bbls of
oil per day from the Miocene sands at an approximate depth of 11,000 feet. Gas
from the block is sold under a two-year, fixed price contract entered into in
April 1995 at an average price of approximately $2.00 per MMbtu.

High Island Block 98-L. High Island Block 98-L is located in shallow
federal waters, offshore Texas. The Company holds a 22% working interest in the
block, where a discovery well was drilled in August 1996. The well logged 153
net feet of productive sand in the Lower Miocene formation at an approximate
depth of 10,000 feet and flow tested at a rate of 9,100 Mcf of gas and 87 Bbls
of condensate per day. The well is expected to be placed on production around
year-end 1996.

Brazos Complex. The Brazos Complex consists of the Brazos Blocks 440-L and
446-L and adjoining undeveloped blocks, located in shallow state waters,
offshore Matagorda County, Texas. The Company is the operator of these blocks
and holds an average working interest of 50% in existing developed acreage and a
75% working interest in several undeveloped blocks. During September 1996, the
Brazos Complex produced approximately 5,700 net Mcf of gas per day from Miocene
sands. In 1995, the Company increased its leasehold position in the Brazos
Complex area and participated in a 400 square mile 3-D seismic survey. Since
January 1, 1994, the Company has drilled five wells on its Brazos acreage, three
of which were successful, and as of September 30, 1996 it was drilling a sixth
well.

SOUTH TEXAS

Approximately 30% of the Company's 1996 exploration and development budget
is allocated to its South Texas operating area. On a pro forma basis, South
Texas represented approximately 10% of total oil and natural gas production
during September 1996 and approximately 7% of the Company's total proved
reserves at June 30, 1996.

A description of American Exploration's major South Texas properties
follows.

AWP Field. The AWP Field is located in McMullen County, Texas and produces
oil and gas from the Olmos sand at an average depth of 9,700 feet. Due to the
tightness of the producing formation, wells require fracturing to produce at
economic rates. The Company operates 102 wells with an average net working
interest of 51%. Two proved undeveloped locations remain to be drilled on the
Company's acreage.

West McAllen Field. The West McAllen Field is located in Hidalgo County,
Texas and produces from a number of Frio sands at depths ranging from 5,800 feet
to 7,500 feet. The Company acquired its interest in the

36
<PAGE> 37

field in December 1993 and entered into a joint venture with Fina Oil and
Chemical to use 3-D seismic data to exploit undrained fault blocks on adjoining
acreage owned by both companies. A total of four wells have been drilled since
1994, three of which were operated by the Company and all of which were
successfully completed. September 1996 production was approximately 2,700 Mcf of
gas per day, net to the Company's average working interest of 66%.

Provident City Area. The Provident City Area is located in Lavaca County,
Texas and has been the primary focus of the Company's South Texas activity since
early 1995. In addition to owning a 30% interest in 13,000 gross acres in the
Provident City Yegua Field, the Company has participated in two Lower Wilcox
discoveries, one in late 1995 and one in 1996, and two Frio discoveries. The
Company also holds a 52.5% working interest in the Yoakum Gorge 3-D project,
located in Lavaca County, where the Company controls over 55,000 acres and is
nearing completion of a 152-square-mile proprietary 3-D survey. The initial
phase of the 3-D data has confirmed over 20 prospects in the shallow Frio and
Yegua formations as well as the deeper Upper and Lower Wilcox formations. The
Company plans to commence drilling 16 of these prospects in the fourth quarter
of 1996.

SMACKOVER TREND

American Exploration's operations in the Smackover Trend of southwestern
Arkansas are focused primarily in the Midway and Buckner fields, both of which
are operated by the Company. The Company's ongoing strategy in this area is to
capitalize on the horizontal drilling expertise it has developed in exploiting
the Midway Field by applying this technology to other Smackover fields.

Buckner Field. The Buckner Field is located approximately 11 miles
southeast of the Midway Field in Lafayette and Columbia Counties, Arkansas. In
1995, the Company acquired a majority of the leases comprising the field and
became operator of 16 wells which produce oil from the Travis Peak and Smackover
formations at depths of less than 7,500 feet. The Company holds a 100% working
interest in the acquired leases, which represent approximately 75% of the total
field area. Oil production for September 1996 averaged approximately 210 barrels
of oil per day, net to the Company's interest. The Buckner Field, which is
geologically similar to Midway, has never been unitized and waterflooded and has
cumulatively produced approximately 12 million barrels of oil from the Smackover
formation, or approximately 30% of estimated original oil in place. The Company
believes that the Buckner Field has significant additional reserve potential and
is currently working to unitize the field and plans to initiate a horizontal
drilling program and waterflood project in 1997.

Midway Field. The Midway Field is located in Lafayette County, Arkansas,
and produces oil from the Smackover Formation at an average depth of 6,500 feet.
The Company became the operator of the field in 1989 and owns an average 64% net
working interest in 49 active wells. The field is a mature waterflood unit that
has produced approximately 80 million barrels of oil since 1942, or
approximately 50% of estimated original oil in place. Since assuming operations,
the Company has been able to increase oil recoveries by drilling horizontal
wells in the uppermost section of the productive formation. Oil production for
September 1996 averaged approximately 500 barrels of oil per day, net to the
Company's interest.

OTHER OPERATING AREAS

In addition to the Company's core operating areas, the Company owns
producing properties and reserves in other areas. The Company seeks to manage
these properties and reserves in a manner which maximizes cash flow available
for reinvestment in the Company's primary areas.

A description of American Exploration's significant properties in other
areas follows.

Bowdoin Field. The Bowdoin Field is located in northern Montana in Phillips
and Valley Counties. The structure was discovered in 1913 by using surface
geology. Gas is trapped in over 400 feet of closure in sandstones at depths less
than 1,500 feet. The Company owns an average net working interest of 17% in
approximately 500 active wells. Another 245 proved undeveloped locations have
been identified, and the Company intends to drill in these locations as
necessary to maintain production capacity at current levels.

37
<PAGE> 38

Gas produced from the Bowdoin Field is sold under a life of lease contract
to KN Gas Supply Services, Inc., a subsidiary of KN Energy, Inc. Pursuant to a
1992 settlement agreement, KN Energy, Inc. prepaid the Company approximately
$2.0 million which was used to repay a long-term production payment that
burdened the field. The Company realized an average price of $3.59 per Mcf for
gas produced from this field during 1995. In February 1995, the Company was
served with a lawsuit requesting a reduction of the contract price to market
levels. See "-- Legal Proceedings."

Bradshaw Field. The Bradshaw Field encompasses approximately 250 square
miles and is located approximately ten miles northwest of the Hugoton Field in
Hamilton County, Kansas. The field produces gas from the Winfield, Fort Riley
and Towanda sands of the Chase Group at depths ranging from 2,600 feet to 2,900
feet. The Company operates 129 active wells with an average net working interest
of 87%. In late 1995, the Company and a subsidiary of KN Energy, Inc., the gas
gatherer in the field, installed additional compression and pipeline facilities
in the field so as to increase production capacity. During the first nine months
of 1996, the Company completed 11 gross (8.7 net) development wells in the field
and completed workovers on three wells. This activity has increased the
Company's net gas production by approximately 56% from an average of
approximately 8,000 Mcf per day in January 1996 to approximately 12,500 Mcf per
day in September 1996.

Henderson Canyon Area. The Henderson Canyon Area includes the Henderson
Canyon Field and the Angus Strawn Field in Crockett County, Texas. The Company
has a 34% average working interest in 73 active wells. Most of the production is
from a single stratigraphically trapped sand body that has a maximum sand
thickness of 160 feet. A total of 12 proved undeveloped locations have been
identified for future drilling.

RESERVES

The following table sets forth summary data with respect to the estimated
proved oil and gas reserves and related present value of estimated future net
revenues of the Company's properties as of June 30, 1996 on a historical basis
and on a pro forma basis after giving effect to the September 1996 Acquisition
and the 1996 Sales. Such estimates on a historical basis are based upon (i) the
quantities of reserves set forth in a reserve report prepared by Netherland,
Sewell & Associates, Inc., independent petroleum engineers, as of December 31,
1995 with respect to the properties owned by the Company as of such date, (ii)
adjustments to such December 31, 1995 reserves made by the Company to reflect
production and drilling activity after such date, which adjustments have been
audited by Netherland, Sewell & Associates, Inc. as set forth in their report
dated October 8, 1996 and included in Appendix A hereto, and (iii) reserve
estimates set forth in the Cobb Report, a copy of which is included in Appendix
A hereto, with respect to the properties acquired in the March 1996 Acquisition.
Such estimates on a pro forma basis are based on (i) the historical basis
estimates as of June 30, 1996 as described above, (ii) adjustments to such June
30, 1996 estimates made by the Company to remove reserves attributable to the
1996 Sales and (iii) reserve estimates set forth in the Cobb Report with respect
to the properties acquired in the September 1996 Acquisition. The estimates of
the SEC-10 Value of the reserves are based upon prices as of June 30, 1996,
except in those instances in which fixed and determinable gas price escalations
are covered by contracts. The prices used as of June 30, 1996 averaged $18.19
per Bbl of oil and $2.25 per Mcf of natural gas.

There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
future net cash flows. The quantities of oil and gas that are ultimately
recovered, production and operating costs, the amount and timing of future
development expenditures and future oil and gas sales prices may all differ from
those assumed in these estimates. Reserve assessment is a subjective process of
estimating recovery from underground accumulations of oil and gas that cannot be
measured precisely, and estimates of other persons might differ from the data
presented herein. Accordingly, reserve estimates may differ significantly from
the quantities of oil and gas that are ultimately recovered. Moreover, the
discounted present value shown below should not be construed as the current
market value of the estimated oil and gas reserves attributable to the Company's
properties. A market value determination would take into account additional
factors including, but not limited to, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.

38
<PAGE> 39

Although the Company prepares an annual estimate of proved oil and gas
reserves, no estimate of total proved net oil and gas reserves of the Company
has been filed with or included in reports to any federal authority or agency,
other than estimates previously filed with the Securities and Exchange
Commission. Except as described above, the Company is not aware of any major
discovery or the occurrence of any other favorable or adverse event since June
30, 1996 that would cause material changes in the quantities of proved reserves
owned by the Company as of such date. The information in this section should be
read in conjunction with the Consolidated Financial Statements of the Company,
including the Notes thereto, included in this Prospectus.

The Company's estimated proved oil and gas reserves at June 30, 1996 on a
historical and pro forma basis are as follows:

<TABLE>
<CAPTION>
JUNE 30, 1996
-----------------------------------------------
HISTORICAL PRO FORMA
--------------------- ---------------------
OIL GAS OIL GAS
RESERVES RESERVES RESERVES RESERVES
(MBBLS) (MMCF) (MBBLS) (MBBLS)
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Proved developed............................. 9,165 112,911 8,857 104,542
Proved undeveloped........................... 1,351 22,428 4,390 40,639
------ ------- ------ -------
Total proved....................... 10,516 135,339 13,247 145,181
====== ======= ====== =======
</TABLE>

The Company's estimated future net cash flows from proved and proved
developed oil and gas reserves at June 30, 1996 and the discounted present value
of such cash flows (before income taxes) on a historical basis and pro forma
basis as described above are as follows (in thousands):

<TABLE>
<CAPTION>
JUNE 30, 1996
----------------------------------------------------
HISTORICAL PRO FORMA
----------------------- -----------------------
PROVED DEVELOPED PROVED DEVELOPED
-------- --------- -------- ---------
<S> <C> <C> <C> <C>
1996................................. $ 25,767(1) $ 27,095 $ 27,853 $ 26,348
1997................................. 42,176(1) 42,552 44,423 40,886
1998................................. 34,125 31,811 43,060 29,445
Remainder............................ 210,724 158,709 241,578 153,624
-------- -------- -------- --------
Total future net cash flows.......... $312,792 $ 260,167 $356,914 $ 250,303
======== ======== ======== ========
Present value before income taxes
(discounted 10%)................... $190,776 $ 168,513 $225,048 $ 162,303
======== ======== ======== ========
</TABLE>

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

(1) For 1996 and 1997, estimated pre-tax future net cash flows from proved
reserves are projected to be lower than estimated pre-tax future net cash
flows from proved developed reserves due to capital expenditures associated
with proved undeveloped reserves during 1996 and 1997 of approximately $2.6
million and $6.5 million, respectively, for development wells.

39
<PAGE> 40

DRILLING

The following table sets forth the results of drilling activity by the
Company for the three years in the period ended December 31, 1995 and for the
nine months ended September 30, 1996.

NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
----------------------------- SEPTEMBER 30,
1993(1) 1994 1995(2) 1996
------- ----- ------- ------------
<S> <C> <C> <C> <C>
DEVELOPMENT WELLS
Gross:
Productive................................ 80 89 40 29
Dry Holes................................. 8 6 7 5
----- ----- ----- -----
Total............................. 88 95 47 34
===== ===== ===== =====
Net:
Productive................................ 11.61 31.52 17.22 10.33
Dry Holes................................. 2.17 1.48 2.18 1.40
----- ----- ----- -----
Total............................. 13.78 33.00 19.40 11.73
===== ===== ===== =====
EXPLORATORY WELLS
Gross:
Productive................................ 2 3 -- 5
Dry Holes................................. 6 3 3 11
----- ----- ----- -----
Total............................. 8 6 3 16
===== ===== ===== =====
Net:
Productive................................ 0.28 0.14 -- 1.59
Dry Holes................................. 1.72 1.11 1.93 5.37
----- ----- ----- -----
Total............................. 2.00 1.25 1.93 6.96
===== ===== ===== =====
</TABLE>

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

(1) Drilling activity for 1993 included six gross (3.19 net) development wells
in Canada, of which 50% were successful, and two gross (0.70 net)
unsuccessful international exploratory wells. The Company sold its Canadian
properties in mid-1993 and sold its other international interests during
1994.

(2) Development wells drilled during 1995 include nine gross (5.99 net)
productive wells and two gross (1.33 net) dry holes drilled in the Sawyer
Field prior to the sale of that field in July 1995.

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<PAGE> 41

PRODUCTION

The following table summarizes the average prices received with respect to
oil and gas produced and sold from, the net volumes of oil and gas produced and
sold from and certain additional information relating to all properties in which
the Company held an interest during the three years in the period ended December
31, 1995 and for the nine months ended September 30, 1996.

NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
------- ------- ------- ------------
<S> <C> <C> <C> <C>
AVERAGE SALES PRICE(1):
Gas ($/Mcf).............................. $ 1.92 $ 1.90 $ 1.74 $ 1.88
Oil($/Bbl)............................... 16.01 15.39 16.83 16.87
BOE ($/BOE).............................. 12.99 12.67 12.30 13.17

PRODUCTION DATA:
Gas (MMcf)............................... 15,336 16,241 24,450 15,772
Oil (MBbls).............................. 1,261 1,241 1,680 1,340
MBOE..................................... 3,817 3,948 5,755 3,969

AVERAGE COST ($/BOE) DATA:
Production and operating costs(2)........ $ 4.19 $ 5.40 $ 4.26 $ 3.89
Taxes other than income.................. 1.21 1.45 1.00 1.07
Depreciation, depletion and
amortization.......................... 6.19 7.50 5.34 5.26
</TABLE>

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

(1) Prices reflect impact of hedging gains and losses.

(2) The amount for 1993 reflects reclassifications of the Company's share of
producing overhead well costs from general and administrative expense to
production and operating costs in order to conform with current
classifications.

PRODUCTIVE WELLS

The following table sets forth information regarding the number of
productive wells in which the Company held a working interest as of June 30,
1996. Productive wells are either producing wells or wells capable of production
although currently shut-in. One or more completions in the same well bore are
counted as one well.

<TABLE>
<CAPTION>
JUNE 30, 1996
--------------
GROSS NET
----- ---
<S> <C> <C>
Oil................................................ 2,562 384
Gas................................................ 2,002 367
----- ---
Total...................................... 4,564 751
===== ===
</TABLE>

ACREAGE

The following table sets forth the approximate developed and undeveloped
acreage in which the Company held a leasehold, mineral or other interest as of
June 30, 1996.

Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned by the
Company. A net acre is deemed to exist when the sum of the Company's fractional
ownership interests in gross acres equals one. The number of net acres is the
sum of the fractional interests owned in gross acres. Included in the following
table are 315,491 gross (16,297 net) developed mineral acres and 789,566 gross
(90,807 net) undeveloped mineral acres, all located in the United States. A
mineral acre is an acre in which the Company

41
<PAGE> 42

has a perpetual interest, as contrasted to a leased acre in which the Company's
interest is typically limited to the life of production or otherwise limited in
time.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------- -------------------
GROSS NET GROSS NET
--------- ------- --------- -------
<S> <C> <C> <C> <C>
United States:
Arkansas..................................... 12,703 4,111 27,127 3,817
Kansas....................................... 157,647 68,336 24,298 6,216
Louisiana.................................... 15,133 2,045 1,554 169
Mississippi.................................. 27,092 4,274 178,428 45,373
Montana...................................... 254,613 33,193 155,535 52,237
New Mexico................................... 16,366 3,020 272,438 38,416
North Dakota................................. 19,929 1,620 7,007 599
Oklahoma..................................... 163,328 22,661 112,700 12,667
Texas........................................ 338,705 41,954 421,769 37,806
Utah......................................... 5,002 1,820 21,160 6,123
Wyoming...................................... 8,505 2,318 14,774 2,308
Eleven other states.......................... 13,462 4,926 55,984 12,152
Gulf of Mexico............................... 71,534 15,457 76,515 28,788
--------- ------- --------- -------
Total United States.................. 1,104,019 205,735 1,369,289 246,671
--------- ------- --------- -------
International:
Canada (1)................................... 22,240 112 149,055 658
New Zealand (1).............................. -- -- 725,992 32,307
--------- ------- --------- -------
Total International.................. 22,240 112 875,047 32,965
--------- ------- --------- -------
Total................................ 1,126,259 205,847 2,244,336 279,636
========= ======= ========= =======
</TABLE>

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

(1) Acreage relates to overriding royalty interests.

TITLE TO PROPERTIES

The Company's properties are subject to customary royalty interests, liens
incident to operating agreements, liens for taxes and other burdens, including
other mineral encumbrances and restrictions. The Company does not believe that
any of these burdens materially interfere with the use of such properties in the
operation of its business. In addition, substantially all of the properties in
which the Company or its subsidiaries own a direct interest are subject to
mortgages granted to secure credit facilities.

A thorough examination of title has been performed with respect to
substantially all of the Company's producing properties, and the Company
believes that it generally holds satisfactory title to such properties. As is
customary in the oil and gas industry, little or no investigation of title is
made at the time of acquisition of undeveloped properties (other than a
preliminary review of local mineral records). Investigations of title are
generally made before commencement of drilling operations and, in most cases,
include the receipt of a title opinion of local counsel.

FOREIGN AND DOMESTIC OPERATIONS

The Company's only industry segment is oil and gas exploration and
production. Since mid-1993, all of the Company's operations have been conducted
in the United States. Certain information concerning the Company's operations by
geographic area is set forth in Note 16 to the Consolidated Financial Statements
included in this Prospectus, which information is incorporated herein by
reference.

OIL AND GAS MARKETING AND COMPETITION

The natural gas produced from the Company's properties is generally sold at
the wellhead under contracts which provide for market-sensitive pricing. The
price of natural gas is influenced by many factors including the

42
<PAGE> 43

state of the economy, weather and competition from other fuels, including oil
and coal. The Company's revenues, cash flows and the value of its gas reserves
are all affected by the level of gas prices.

The crude oil and condensate produced from the Company's properties are
generally sold to other companies at field prices posted by the principal
purchasers of crude oil in the areas where such properties are located. As is
customary in the industry, this production is generally sold pursuant to
short-term contracts.

In the year ended December 31, 1995, sales to Enron Corp. and certain
subsidiaries of KN Energy, Inc. accounted for approximately 19% and 10%,
respectively, of the Company's oil and gas revenues. Because of the availability
of other customers, management does not believe that the loss of any single
customer would adversely affect the Company's operations.

The oil and gas industry is highly competitive. Major oil and gas
companies, independent producers, drilling and production purchase programs and
individual producers and operators are active competitors for desirable oil and
gas properties, as well as for the equipment and labor required to develop and
operate such properties. Many competitors have financial resources, staffs and
facilities substantially larger than those of the Company. The availability of a
ready market for the oil and gas production of the Company depends in part on
the cost and availability of alternative fuels, the level of consumer demand,
the extent of other domestic production of oil and gas, the extent of imports of
foreign oil and gas, the cost of and proximity to pipelines and other
transportation facilities, regulations by state and federal authorities and the
cost of complying with applicable environmental regulations.

EMPLOYEES

As of September 30, 1996, the Company had 162 full-time employees, none of
whom is represented by any labor union.

REGULATION

The following discussion of the regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders which affect the
Company or to which operations of the Company may be subject.

Federal Regulation of Natural Gas. Certain sales and the transportation of
natural gas in interstate commerce are regulated under various federal laws
including, but not limited to, the Natural Gas Act of 1938 ("NGA") and the
Natural Gas Policy Act of 1978 ("NGPA"), both of which are administered by the
Federal Energy Regulatory Commission ("FERC"). Under these acts, producers and
marketers have historically been required to obtain from the FERC certificates
to make so-called "first sales" and abandonment authority to discontinue such
sales. Additionally, first sales have been subject to maximum lawful price
regulation. However, the NGPA provided for phased-in price deregulation of most
new gas production and, as a result of the enactment of the Natural Gas Wellhead
Decontrol Act of 1989, the remaining regulations imposed by the NGA and the NGPA
with respect to first sales, including price controls and certificate and
abandonment authority regulations, were terminated on January 1, 1993. The
FERC's jurisdiction over transportation and sales other than first sales has not
been affected, although the FERC has effectively deregulated even these
non-first sales by granting the pipeline companies and local distribution
companies so-called "blanket certificates" to make sales at negotiated market
prices.

Commencing in the mid-1980s, the FERC promulgated several orders designed
to make gas markets more competitive by, among other things, inducing or
requiring interstate natural gas pipeline companies to provide transportation
services on an open and nondiscriminatory basis. These orders have had a
profound influence upon natural gas markets in the United States and have, among
other things, encouraged many new marketing entities to enter the market and
fostered the development of a large spot market for gas.

In April 1992, the FERC issued the latest in this series of orders, Order
No. 636. Order No. 636 further restructured the sales and transportation
services provided by interstate pipeline companies. The FERC considered these
changes necessary to improve the competitive structure between interstate
pipelines and other gas merchants, including producers, and to create a
regulatory framework that would allow more gas

43
<PAGE> 44

sellers to contract directly with gas buyers. Order No. 636 was implemented on a
pipeline-by-pipeline basis through negotiated settlements in individual pipeline
service restructuring proceedings, designed specifically to "unbundle" those
services (e.g., transportation, sales and storage) provided by many interstate
pipelines. As a result, in many instances, the interstate pipelines themselves
are no longer wholesalers of natural gas, but instead provide only natural gas
storage and transportation services. On rehearing before the FERC, the agency
made relatively minor modifications. In addition, the FERC has issued orders in
individual pipeline restructuring proceedings which were the subject of further
rehearing. Order No. 636 and certain related proceedings were the subject of an
appeal to the United States Court of Appeals for the District of Columbia
Circuit. That court recently issued its decision in the appeal of Order No. 636
and largely upheld the fundamental tenets of the order. The court's decision is
still subject to further action, including potential applications for a writ of
certiorari to the United States Supreme Court. In addition, several appeals in
individual pipeline proceedings and as to related issues remain pending. It is
therefore not possible for the Company to predict what effect, if any, the
ultimate outcome of this regulatory and judicial review process will have on the
FERC's open-access regulations.

Order No. 636 does not regulate gas producers such as the Company. To date,
management of the Company believes Order No. 636 has not had any significant
impact on the Company as a producer or on the Company's gas marketing efforts.

The FERC is currently considering several other rules intended to
streamline its regulation of the industry and promote competition. One such rule
under consideration concerns pipeline rates. For decades, the principal
methodology used to set interstate pipeline rates has been based on the actual
costs to provide that service. In recent years, regulators have concluded that
sufficient competition may exist in certain markets to allow a relaxation of
this historic approach. In January 1996, the FERC issued a statement of policy
and request for comments concerning alternatives to its traditional
cost-of-service ratemaking methodology and set forth the criteria that the FERC
will use to evaluate proposals to charge market-based rates for the
transportation of natural gas. The FERC also requested comments on whether it
should allow gas pipelines the flexibility to negotiate the terms and conditions
of transportation service with prospective shippers. In another rulemaking, the
FERC is considering how to alter its regulations to promote the fair and
effective release and recontracting of pipeline capacity from one shipper to
another, and to what extent such transactions should be regulated where the
market is demonstrably competitive. In this regard, an experimental pilot
program implementing certain new procedures will be implemented in the 1996-1997
winter heating season. Lastly, the FERC has issued a policy statement on how
interstate pipelines can recover in rates the costs of new facilities. While the
policy may affect the Company and other producer-shippers only indirectly, the
policy should enhance competition in new markets and encourage the construction
of gas supply laterals. As to all of these matters, the Company cannot predict
what further action the FERC will take; however, the Company does not believe
that it will be affected by any action taken materially differently than other
natural gas producers, gatherers and marketers with which it competes.

Commencing in May 1994, the FERC began to delineate a new gathering policy
in light of Order No. 636. As a general matter, gathering, which is the
transportation of gas in or near the field where produced to points of
interconnect with large diameter, high pressure transportation pipelines, is
exempt from the FERC's jurisdiction; however, where the gathering is performed
by the interstate pipelines in association with the pipeline's jurisdictional
transportation activities, the FERC retains regulatory control over the
associated gathering services to prevent abuses. Except in situations in which
the gatherer acts in concert with an interstate pipeline affiliate to frustrate
the FERC's transportation policies, the FERC does not generally have
jurisdiction. In addition, the FERC has approved several transfers proposed by
interstate pipelines of gathering facilities to unregulated independent or
affiliated gathering companies. The FERC's policy of approving the interstate
pipeline's proposed "spindown" of its gathering facilities to an unregulated
affiliate company has recently been upheld on judicial review, but the court
reversed and remanded that portion of the FERC's orders by which the unregulated
affiliate was obligated to continue existing gathering services to producers
under "default contracts" for up to two years after spindown. It remains unclear
whether the FERC will attempt to reimpose such conditions or will otherwise act
in response to producer requests for additional protection against perceived
monopolistic action by pipeline-related gatherers. While changes to the FERC's

44
<PAGE> 45

gathering policy affect the Company only indirectly, such changes could affect
the price and availability of capacity on certain gathering facilities, and thus
access to certain interstate pipelines, which, in turn, could affect the price
of gas at the wellhead and in markets in which the Company competes. However,
the Company does not believe that it will be affected by these changes to the
FERC's gathering policy materially differently than other natural gas producers
with which it competes.

Regulation of Drilling and Production. Exploration and production
operations of the Company are subject to various types of regulation at the
federal, state and local levels. Such regulation includes requiring drilling
permits, requiring the maintenance of bonds in order to drill or operate wells
and regulating the location of wells, the method of drilling and casing wells,
the surface use and restoration of properties upon which wells are drilled and
the plugging and abandoning of wells. The operations of the Company are also
subject to various conservation regulations, including regulation of the size of
drilling and spacing units or proration units, the density of wells that may be
drilled and the unitization or pooling of oil and gas properties. In this
regard, some states, including states in which the Company operates, allow the
forced pooling or integration of lands and leases. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amount of crude oil and natural gas the Company can produce from its
wells and the number of wells or the locations at which the Company can drill.

Future Legislation and Regulation. The Company's business is and will
continue to be affected from time to time in varying degrees by political
developments and federal, state and local laws and regulations. The Company is
not able to predict the terms of any future legislation or regulations that
might ultimately be enacted or the effects of any such legislation or
regulations on the Company.

ROYALTY MATTERS

By a letter in May 1993 directed to thousands of producers holding
interests in federal leases, the United States Department of the Interior (the
"Department") announced its interpretation of certain administrative regulations
to require the payment of royalties on natural gas contract settlements to
resolve, among other things, take-or-pay and minimum take claims by producers
against pipelines and other buyers. The Department's letter set forth various
theories of liability, all founded on the Department's interpretation of the
term "gross proceeds" as used in federal leases and pertinent federal
regulations. In an effort to ascertain the amount of such potential royalties,
the Department sent a letter to producers in 1993 requiring producers to provide
data on natural gas contract settlements where gas produced from federal or
Indian leases was involved in the settlement. The Company received a copy of
this information demand letter and responded appropriately in May 1994. To date,
the Company has received one order to pay additional royalties based on the
information supplied to the Department.

In response to the Department's action, various industry associations,
including the Independent Petroleum Association of America, and others filed
suit seeking an injunction to prevent the collection of royalties on natural gas
contract settlement amounts under the Department's theories. At the federal
district court level, the court ruled in favor of the government's position.
However, on appeal to the United States Court of Appeals for the District of
Columbia Circuit, the federal appellate court on August 27, 1996 overturned the
lower court's opinion and held that the government's position was contrary to
certain prior court precedents and inconsistent with the government's prior
position in response to those precedents. In October 1996, the Department filed
a Petition for Rehearing and Suggestion for Rehearing in Banc with the federal
appellate court. Notwithstanding the recent outcome that was favorable to the
industry, the Company cannot predict what further action will be taken by the
appellate courts and what effect, if any, the Department's claims will have on
the Company. Furthermore, even if the Department's claims are reestablished by
further appellate decision, certain of the Company's natural gas contract
settlements provide for the buyer to reimburse the Company for any excess or
additional payments to royalty owners required as a result of the Company's
receipt of the settlement amounts.

45
<PAGE> 46

ENVIRONMENTAL MATTERS

The Company and its operations are subject to a number of federal, state
and local laws and regulations governing the discharge of materials into the
environment or otherwise relating to the protection of the environment. These
environmental provisions may, among other things, impose liabilities for the
cost of pollution clean-up resulting from drilling operations, prohibit drilling
on certain lands and impose restrictions on the injection of liquids into
underground water sources that may, in turn, contaminate groundwater.

The Company believes it has acted as a prudent operator and is in
substantial compliance with environmental laws and regulations. The Company has
incurred and will continue to incur costs in its efforts to comply with these
environmental standards. Although the costs incurred by the Company to date
solely to comply with environmental laws and regulations have not had a material
adverse effect upon capital expenditures, earnings or the competitive position
of the Company, the trend toward stricter environmental laws and regulations is
expected to have an increasingly significant impact on the conduct of the
Company's business. The cost of expenditures to comply with evolving regulations
and the related future impact on the Company's business cannot be predicted at
this time because of the uncertainties regarding future environmental standards,
advances in technology, the timing for expending funds and the availability of
insurance and third-party indemnification. However, the Company believes that
the evolving environmental standards do not affect the Company in a materially
different manner from other similarly situated companies in the oil and gas
industry.

OPERATING HAZARDS AND UNINSURED RISKS

The Company's operations are subject to all of the risks normally incident
to the exploration for and the development and production of oil and gas,
including blowouts, cratering, uncontrollable flows of oil, gas or well fluids,
fires, pollution and other environmental risks. These hazards could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property and equipment, pollution and other environmental
damage and suspension of operations. Although the Company is not fully insured
against certain of these risks, it maintains insurance coverage considered to be
customary in the industry.

LEGAL PROCEEDINGS

NYLOG Litigation. The Company and its subsidiary, American Exploration
Production Company ("AEPCO" and, together with the Company, the "American
Parties"), along with New York Life and several of its subsidiaries, were named
as defendants in a class action complaint filed in the United States District
Court for the Southern District of Florida on March 18, 1996, styled Shea et al.
v. New York Life Insurance Co., et al. (Civil Action No. 96-0746), alleging
generally that the defendants engaged in fraudulent activities in connection
with the marketing and sale of interests in, and the subsequent operation of,
various limited partnerships, breached implied covenants and fiduciary duties
and violated various federal securities and state laws and rules. A subsidiary
of New York Life ("NYLIFE") agreed to indemnify the American Parties from and
against any and all judgments or settlements entered or reached in this
litigation and certain related litigation, or any subsequent lawsuits by
investors in the NYLOG Programs based on substantially similar claims and
factual allegations. The defendants expressly denied any wrongdoing alleged in
the complaints and conceded no liability or wrongdoing. Nevertheless, to reduce
the burden of protracted litigation, the defendants entered into a Stipulation
of Settlement (the "Settlement Agreement") with the approval of the Florida
court, providing for the liquidation of the NYLOG Programs and the release and
discharge of the defendants and various other related parties. Pursuant to the
Settlement Agreement, each limited partner of a limited partnership who
participated in the settlement received or will receive from an affiliate of New
York Life a cash payment that, together with prior distributions to such
settling limited partner from such limited partnership, will result in the
settling limited partner having received in the aggregate an amount at least
equal to his total investment in such partnership. In July 1996, the limited
partners of the NYLOG Programs approved the liquidation of the partnerships, and
the Company anticipates that the liquidating sales of the properties held by the
NYLOG Programs will be completed during the fourth quarter of 1996.

46
<PAGE> 47

New York Life and certain of its subsidiaries and AEPCO have also been
named as defendants in a lawsuit relating to the NYLOG Programs styled Billy H.
Mancil and Mary M. Mancil v. New York Life Insurance Company, et al., Civil
Action No. CV-95-2595 GR, Circuit Court of Montgomery County, Alabama (the
"Mancil Litigation"). The complaint in the Mancil Litigation alleges various
causes of action arising out of Mancil's purchase of interests in certain NYLOG
Programs including, among other things, fraud, reckless and negligent
misrepresentations, and negligence in hiring, training and/or supervising a
sales agent involved in the sale of the NYLOG interests. Plaintiffs seek an
unspecified amount of compensatory and punitive damages and costs. The Mancil
Litigation is covered by the indemnification agreement described in the
foregoing paragraph.

KN Litigation. In February 1995, two Company affiliates were served with a
lawsuit styled KN Gas Supply Services, Inc. v. American Production
Partnership-V, Ltd. and Ninian Oil Finance Corp., filed in United States
District Court in Denver, Colorado, requesting declaratory judgment that KN Gas
Supply Services, Inc. ("KNGSS") had the right to reduce the contract price for
gas produced from the Bowdoin Field to market levels from October 1, 1993
forward. KNGSS also requested declaratory judgment that it has a right to relief
from the contract price due to regulatory changes, which it alleges renders the
contract commercially impracticable, and that FERC Order No. 636 is a condition
subsequent that excuses performance under the contract. KNGSS alleges that it
has overpaid the Company's affiliates and seeks a refund of approximately $5.6
million for the period through December 1995. A Motion for Summary Judgment was
filed by the Company in July 1996 and is currently pending before the court.
Trial is currently scheduled to begin in January 1997. Although the Company
cannot predict the outcome of this proceeding, the Company will vigorously
defend its interest in this case and does not expect the outcome of the case to
have a material adverse impact on its financial position or results of
operations.

Other. The Company has been named as a defendant in certain other lawsuits
arising in the ordinary course of business. While the outcome of these other
lawsuits cannot be predicted with certainty, the Company does not expect these
other lawsuits to have a material adverse effect on the financial position,
results of operations or liquidity of the Company.

47
<PAGE> 48

MANAGEMENT

Set forth below is certain information regarding the directors and
executive officers of the Company, together with their ages (as of September 30,
1996). All directors and executive officers are elected for a term of one year
and serve until their successors are elected and have qualified.

<TABLE>
<CAPTION>
NAME OFFICE AGE
- ------------------------------- ------------------------------------------------------ ---
<S> <C> <C>
Mark Andrews................... Chairman of the Board and Chief Executive Officer 46
John M. Hogan.................. Senior Vice President and Chief Financial Officer 52
Harold M. Korell............... Senior Vice President -- Operations 51
Cindy L. Gerow................. Vice President and Controller 32
Harry C. Harper................ Vice President -- Land 57
Robert R. McBride, Jr. ........ Vice President -- Production Operations 40
T. Frank Murphy................ Vice President -- Corporate Finance and Secretary 41
Elliott Pew.................... Vice President -- Exploration 41
Harry W. Colmery, Jr. ......... Director 72
Irvin K. Culpepper, Jr. ....... Director 48
Walter J.P. Curley, Jr. ....... Director 74
Robert M. Danos................ Director 66
Phillip Frost, M.D. ........... Director 59
Peter G. Gerry................. Director 51
H. Phipps Hoffstot, III........ Director 40
John H. Moore.................. Director 70
Peter P. Nitze................. Director 61
</TABLE>

Mark Andrews, Chairman of the Board and Chief Executive Officer, founded
the Company in 1980. Mr. Andrews is also a director of IVAX Corporation.

John M. Hogan, Senior Vice President and Chief Financial Officer, who had
previously served as Senior Vice President -- Finance of the Company during 1985
and 1986, rejoined the Company in August 1992. From 1987 until 1992, Mr. Hogan
owned an accounting firm that provided tax, accounting and management services.

Harold M. Korell, Senior Vice President -- Operations, joined the Company
in June 1992. He was Executive Vice President of McCormick Resources, a private
independent oil and gas company, from 1989 until 1992. From 1973 to 1989, Mr.
Korell was with Tenneco Oil Company where he served in various positions and
eventually as Vice President of Production.

Cindy L. Gerow, Vice President and Controller, joined the Company in
October 1990. She served in a number of managerial positions with responsibility
for various accounting and finance functions. She was appointed Controller of
the Company in April 1994 and was appointed Vice President in August 1995.

Harry C. Harper, Vice President -- Land, joined the Company in 1990 when
the Company acquired Hershey Oil Corporation. He had been Senior Vice President,
Secretary and General Counsel of Hershey since 1973.

Robert R. McBride, Jr., Vice President -- Production Operations, joined the
Company in August 1992. From 1988 to 1992, he served in various capacities with
British Gas plc, most recently as Exploitation Manager.

T. Frank Murphy, Vice President -- Corporate Finance and Secretary, joined
the Company in 1989. He served in a variety of financial positions until
December 1991 when he was appointed Vice President -- Investor Relations. He was
appointed Vice President -- Corporate Finance in March 1993 and was appointed
Secretary in October 1993.

Elliott Pew, Vice President -- Exploration, joined the Company in October
1992 as a senior geophysicist. He was appointed Vice President -- Exploration in
July 1993. From 1989 to 1992, he was employed by FINA, Inc. as a division
geologist and then as Exploration Manager -- South Texas Division.

48
<PAGE> 49

Harry W. Colmery, Jr. has served as a director of the Company since 1990.
Mr. Colmery has been a Vice President of Capital Guardian Trust Company of Los
Angeles since 1986.

Irvin K. Culpepper, Jr. has served as a director of the Company since 1989
and is a Vice President of Kelso & Company, a merchant banking firm engaged in
the leveraged buyout business. Mr. Culpepper joined Kelso & Company in 1988.
Prior thereto, he was Vice President in charge of Private Finance for New York
Life Insurance Company. Mr. Culpepper is also a director of Pepper Co., Inc. and
is a director of the New York City Industrial Development Agency.

Walter J. P. Curley, Jr. has been a director of the Company since March
1993 and previously served as a director from 1982 to 1988. Ambassador Curley
was Ambassador to France from 1989 to 1993 and Ambassador to Ireland from 1975
to 1977. He is Principal of W.J.P. Curley, a venture capital company. Ambassador
Curley is also a director of Sothebys Inc. and France Growth Fund and serves on
the international Board of Directors of Banque Paribas. He is president of
Curley Land Company and Trustee of the Frick Collection in New York City.

Robert M. Danos was appointed as a director of the Company in September
1996. Mr. Danos retired in January 1995 from his position as President and a
director of Plains Petroleum Company, an oil and gas exploration company. He
served as the President from October 1994 to January 1995 and as a director from
1989 to January 1995 of Plains Petroleum Company, and from January 1989 to
October 1994 served as the President and Chief Operating Officer of Plains
Petroleum Operating Company, its operating subsidiary. Previously, he was
President of McMoRan Oil and Gas Company, President and Chief Executive Officer,
Midlands Energy and Senior Vice President, KN Energy.

Phillip Frost, M.D., has served as a director of the Company since 1983.
Dr. Frost has been Chairman of the Board and Chief Executive Officer of IVAX
Corporation, a pharmaceutical, medical diagnostic and specialty chemical
company, since March 1987. He is the Vice Chairman of the Board of Directors of
North American Vaccine, Inc. Dr. Frost was also Chairman of the Department of
Dermatology of Mount Sinai Medical Center of Greater Miami from 1972 to 1990. He
is also a director of NAPRO Therapeutics, Inc. and Whitman Education Group, Inc.
Dr. Frost is a trustee of the University of Miami and a governor of the AMEX.

Peter G. Gerry has been a director of the Company since 1983. He has served
as Managing Director of Sycamore Management Corporation, an investment
management firm, since 1995. Mr. Gerry is also Chairman of Seven Up/RC Bottling
Company of Southern California, Inc. and is a former President of Citicorp
Venture Capital Ltd. and director of Pond Hill Homes, Ltd.

H. Phipps Hoffstot, III has served as a director of the Company since 1983.
Mr. Hoffstot is Chief Financial Officer of Pittsburgh History & Landmarks
Foundation and subsidiaries. Mr. Hoffstot has also been engaged as a private
investor since 1979.

John H. Moore was appointed as a director of the Company in 1989. He has
been primarily engaged as a petroleum consultant since 1988. Mr. Moore was
Chairman of the Board and Chief Executive Officer of Ladd Petroleum Corporation
from 1986 to 1988. He is also a former director of First Interstate Bank of
Denver and is a former director of General Atlantic Resources.

Peter P. Nitze has served as a director of the Company since 1983. He has
served as Chairman of Nitze-Stagen & Company, Inc., a real estate and financial
consulting firm, since 1970.

The Board of Directors of the Company has four standing committees: the
Executive Committee, the Audit Committee, the Compensation Committee and the
Nominating Committee. During 1995, the Executive Committee was composed of
Messrs. Andrews, Culpepper, Gerry, Moore and Nitze; the Audit Committee was
composed of Messrs. Nitze, Gerry and Moore; the Compensation Committee was
composed of Messrs. Culpepper and Hoffstot and Ambassador Curley; and the
Nominating Committee was composed of Messrs. Nitze, Andrews and Moore and
Ambassador Curley.

49
<PAGE> 50

SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN BENEFICIAL OWNERS

The table below sets forth information concerning (i) the only persons
known by the Company, based on statements filed by such persons pursuant to
Section 13(d) or 13(g) of the Exchange Act, to own beneficially in excess of 5%
of the Common Stock as of September 30, 1996 and (ii) the shares of Common Stock
beneficially owned, as of September 30, 1996, by each director, the Chief
Executive Officer and the four other most highly compensated officers who were
serving at the end of the Company's last fiscal year and all directors and
executive officers as a group. Pursuant to Rule 13d-3(d)(1) under the Exchange
Act, the table includes shares of Common Stock that can be acquired through the
exercise of options, warrants or convertible securities within 60 days. The
percent of the class owned by each such person has been computed assuming the
exercise of all such options, warrants and convertible securities deemed to be
beneficially owned by such person, and assuming that no options, warrants or
convertible securities held by any other person have been exercised. Except as
indicated, each person has sole voting power and sole investment power over all
shares listed opposite his or its name.

<TABLE>
<CAPTION>
NUMBER OF
SHARES PERCENT
OF COMMON STOCK OF CLASS
--------------- --------
<S> <C> <C>
General Electric Pension Trust............................... 1,995,559(1) 16.4%
3003 Summer Street
Stamford, Connecticut 06904
New York Life Insurance Company+............................. 1,148,196(2) 9.6
51 Madison Avenue
New York, New York 10010
Massachusetts Mutual Life Insurance Company.................. 973,972(3) 8.0
1295 State Street
Springfield, Massachusetts 01111
UNUM Corporation............................................. 799,438(4) 6.8
2211 Congress Street
Portland, Maine 04122
Mark Andrews................................................. 272,326(5) 2.3
Harry W. Colmery, Jr.*....................................... 9,557 **
Irvin K. Culpepper, Jr.*..................................... 3,000 **
Walter J.P. Curley, Jr.*..................................... 14,000 **
Robert M. Danos*............................................. 2,600 **
Phillip Frost, M.D.*......................................... 241,946(6) 2.0
Peter G. Gerry*.............................................. 4,125 **
H. Phipps Hoffstot, III*..................................... 59,613(7) **
John H. Moore*............................................... 4,531 **
Peter P. Nitze*.............................................. 42,509(8) **
John M. Hogan................................................ 30,759(9) **
Harold M. Korell............................................. 51,475(10) **
Robert R. McBride, Jr. ...................................... 10,199(11) **
Elliott Pew.................................................. 12,615(12) **
All directors and executive officers as a group (17
persons)................................................... 788,675(13) 6.6
</TABLE>

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

+ See "Selling Stockholders."

* Amounts include 3,000 shares issuable upon exercise of stock options,
except that the amount for Mr. Danos includes 2,500 such shares and the
amounts for Messrs. Curley and Moore each include 4,531 such shares.

** Less than one percent.

50
<PAGE> 51

(1) Includes 333,333 shares of Common Stock issuable upon conversion of the
Convertible Preferred Stock, represented by 200,000 depositary shares (the
"Depositary Shares"), each representing a 1/200 interest in a share of the
Convertible Preferred Stock.

(2) Includes shares held by a subsidiary of New York Life and 166,667 shares
issuable upon conversion of Convertible Preferred Stock represented by
100,000 Depositary Shares.

(3) Includes 629,500 shares of Common Stock and 344,472 shares issuable upon
exercise of warrants to purchase Common Stock.

(4) Based upon a Schedule 13G, as amended, filed by UNUM Corporation with the
Securities and Exchange Commission (the "Commission" or the "SEC").

(5) Includes 55,848 shares held directly or indirectly by Mr. Andrews' children
and a company of which Mr. Andrews' wife is a principal shareholder and a
director, and as to which shares he disclaims beneficial ownership. Also
includes 64,100 shares issuable upon exercise of stock options and 1,420
shares allocated to Mr. Andrews under the American Exploration 401(k) Plan
(the "401(k) Plan").

(6) Includes 66,667 shares issuable upon conversion of Convertible Preferred
Stock represented by 40,000 Depositary Shares.

(7) Includes 40,113 shares over which Mr. Hoffstot shares investment and voting
power and as to which shares he disclaims beneficial ownership.

(8) Includes 28,842 shares owned by general partnerships of which Mr. Nitze is
a general partner and over which he shares voting and investment power and
6,667 shares issuable upon conversion of Convertible Preferred Stock
represented by 4,000 Depositary Shares.

(9) Includes 16,625 shares issuable upon exercise of stock options and 572
shares allocated to Mr. Hogan under the 401(k) Plan.

(10) Includes 1,667 shares issuable upon conversion of Convertible Preferred
Stock represented by 1,000 Depositary Shares, 26,625 shares issuable upon
exercise of stock options and 374 shares allocated to Mr. Korell under the
401(k) Plan.

(11) Includes 6,375 shares issuable upon exercise of stock options and 386
shares allocated to Mr. McBride under the 401(k) Plan.

(12) Includes 6,375 shares issuable upon exercise of stock options and 427
shares allocated to Mr. Pew under the 401(k) Plan.

(13) These shares include, for all executive officers other than the Chief
Executive Officer and the four other most highly compensated officers,
15,425 shares issuable upon exercise of stock options and 5,664 shares
allocated to officers under the 401(k) Plan.

51
<PAGE> 52

SELLING STOCKHOLDERS

In connection with the Offering, New York Life and one of its subsidiaries
(collectively referred to in this section as "New York Life") and The Prudential
Insurance Company of America ("Prudential Insurance" and, together with New York
Life, the "Selling Stockholders") are exercising their rights to include in the
Offering 379,229 shares and 200,000 shares of Common Stock, respectively,
pursuant to certain registration rights previously granted by the Company (the
"Registration Rights"). New York Life has also granted the Underwriters an
over-allotment option to purchase 56,884 additional shares. Prior to the
Offering, New York Life beneficially owned 1,148,196 shares of Common Stock.
Upon completion of the Offering, New York Life will own 768,967 shares of Common
Stock (712,083 shares if the over-allotment options are exercised in full)
representing approximately 5.1% of the total shares outstanding (approximately
4.5% if the over-allotment options are exercised in full). For additional
information concerning the Selling Stockholders, see "Security Ownership of
Management and Certain Beneficial Owners," "Certain Transactions and Related
Transactions" and "Underwriting."

Pursuant to the Registration Rights, the Company is paying all the expenses
of the Offering, including the expenses attributable to the shares being sold by
the Selling Stockholders, other than underwriting discounts and commissions, any
transfer taxes attributable to such shares, and any fees or expenses of counsel
for one of the Selling Stockholders.

52
<PAGE> 53

EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table sets forth certain information with respect to the
compensation for the years 1995, 1994 and 1993 for the Company's Chief Executive
Officer and the four highest paid executive officers other than the Chief
Executive Officer who were serving at the end of the Company's last fiscal year.
All 1993 and 1994 share amounts and prices are adjusted for the 1995 one-for-ten
reverse stock split of the Common Stock.

<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
AWARDS
-------------------------
SECURITIES
UNDERLYING
ANNUAL COMPENSATION RESTRICTED OPTIONS/SARS
NAME AND -------------------- STOCK (OPTION UNITS) ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS AWARDS(1) (SHARES) COMPENSATION(2)
- --------------------------- ---- -------- -------- -------- -------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Mark Andrews............... 1995 $286,662 $200,000 None 120,000(3) $ 6,900
Chairman and Chief 1994 270,000 75,000 None None 210,316
Executive Officer 1993 270,000 60,000 430,513 68,200(4) 147,919
John M. Hogan.............. 1995 189,583 100,000 None 20,000(3) 1,050
Senior Vice President and 1994 175,000 65,000 None None 5,437
Chief Financial Officer 1993 150,000 50,000 146,766 23,250(4) 1,318
Harold M. Korell........... 1995 202,500 100,000 None 60,000(3) 1,050
Senior Vice President -- 1994 190,000 50,000 None None 5,437
Production 1993 183,413 57,000 146,766 23,250(4) 1,318
Robert R. McBride, Jr...... 1995 140,000 35,000 None 10,000(3) 1,050
Vice President -- 1994 140,000 30,000 None None 2,261
Production Operations 1993 137,804 28,000 48,922 7,750(4) 1,050
Steven L. Mueller.......... 1995 140,000 35,000 None 10,000(3) 1,050
Vice President --
Exploitation.............. 1994 140,000 30,000 None None 2,512
1993 137,804 28,000 48,922 7,750(4) 1,050
</TABLE>

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

(1) Granted in October 1993 under the Company's Stock Compensation Plan (the
"1983 Plan"). One-third of the shares vested on the second anniversary of
the grant, one-third of the shares vested on the third anniversary of the
grant and one-third of the shares will vest on the fourth anniversary of the
grant. The total number of shares of Restricted Common Stock held by the
named officers as of December 31, 1995 and the total value thereof based on
the $13.125 per share closing price of the Common Stock on the AMEX at the
grant date were as follows: Mr. Andrews -- 34,100 shares: $447,563; Mr.
Korell -- 11,625 shares: $152,578; Mr. Hogan -- 11,625 shares: $152,578; Mr.
McBride -- 2,583 shares: $33,901; and Mr. Mueller -- 3,870 shares: $50,859.
The aggregate number and value of all Restricted Common Stock Awards totaled
79,725 shares and $1,046,391. To the extent paid on shares of Common Stock,
dividends will also be paid on Restricted Common Stock.

(2) All other compensation for 1995 consisted of the following: (i) Company
contributions to the 401(k) Plan of $1,050 for each of the named officers;
and (ii) Company-paid life insurance premiums for Mr. Andrews of $5,850.

(3) Amounts represent options granted under the 1994 Stock Compensation Plan
(the "1994 Plan") which was approved by stockholders at the 1995 Annual
Meeting. The numbers of options granted under the 1994 Plan were as follows:
Mr. Andrews -- 40,000 shares; Mr. Hogan -- 20,000 shares; Mr. Korell --
20,000 shares; Mr. McBride -- 10,000 shares; and Mr. Mueller -- 10,000
shares. In addition, Mr. Andrews was permitted to purchase up to 10,000
shares of Common Stock, the purchase of which would provide options with a
$12.50 exercise price at a rate of eight options for each share of Common
Stock purchased during a specified period. Mr. Andrews has purchased the
full 10,000 shares. In addition, Mr. Hogan and Mr. Korell were each
permitted to purchase up to 5,000 shares of Common Stock, the purchase of
which would provide options with a $12.50 exercise price at a rate of eight
options

53
<PAGE> 54

for each share of Common Stock purchased during a specified period. Mr.
Hogan elected not to purchase shares and Mr. Korell has purchased the full
5,000 shares.

(4) Amounts represent option units granted in October 1993 under the Company's
Phantom Stock Plan (the "Phantom Plan"). One quarter of the option units
vest on each anniversary of the grant. In June 1995, the option units were
converted to options with the same option price and vesting period as the
original option units.

OPTION/SAR GRANTS

The following table sets forth certain information with respect to options
granted under the 1994 Plan.

<TABLE>
<CAPTION>
POTENTIAL REALIZABLE
VALUE AT ASSUMED
% OF TOTAL ANNUAL RATES OF STOCK
OPTIONS PRICE APPRECIATION
NUMBER GRANTED TO EXERCISE FOR TERM
OF OPTIONS PARTICIPANTS PRICE EXPIRATION ---------------------
NAME AND POSITION GRANTED IN 1995 ($/UNIT) DATE(1) 5% 10%
- ------------------------------- ---------- ----------- -------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Mark Andrews(2)................ 120,000 27.5% $12.50 10/31/2004 $2,443,342 $3,890,614
Chairman of the Board and
Chief Executive Officer
John M. Hogan(3)............... 20,000 4.6% 12.50 10/31/2004 407,224 648,436
Senior Vice President and
Chief Financial Officer
Harold M. Korell(4)............ 60,000 13.7% 12.50 10/31/2004 1,221,671 1,945,307
Senior Vice President --
Operations
Robert R. McBride, Jr. ........ 10,000 2.3% 12.50 10/31/2004 203,612 324,218
Vice President -- Production
Operations
Steven L. Mueller.............. 10,000 2.3% 12.50 10/31/2004 203,612 324,218
Vice President -- Exploitation
</TABLE>

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

(1) Granted on November 1, 1994 subject to stockholder approval which was
received on June 13, 1995. No more than one quarter of the options vest on
each anniversary date of the grant; the options remain outstanding for a
period of ten years.

(2) Includes 80,000 options awarded to Mr. Andrews with a $12.50 exercise price
at a rate of eight options for each share of Common Stock purchased during a
specified period. Mr. Andrews has purchased the full 10,000 shares of Common
Stock.

(3) In addition, Mr. Hogan was awarded up to 40,000 options with a $12.50
exercise price at a rate of eight options for each share of Common Stock
purchased during a specified period. Mr. Hogan elected not to exercise his
right to purchase shares of Common Stock.

(4) Includes 40,000 options awarded to Mr. Korell with a $12.50 exercise price
at a rate of eight options for each share of Common Stock purchased during a
specified period. Mr. Korell has purchased the full 5,000 shares of Common
Stock.

In addition to the options granted above, at the election of the employees,
the employees were permitted to convert their remaining option units granted
under the Phantom Plan in 1993 to Incentive Stock Options under the 1994 Plan to
the extent permitted and Nonqualified Stock Options at the original option unit
price. The options will vest at the same rate as the option units with a term of
ten years from the original option units award date. The 1994 Plan was approved
at the 1995 Annual Meeting and approximately 154,113 additional options were
issued under the 1994 Plan, including 113,775 options to the Executive Group and
40,338 to the Non-Executive Officer Employee Group. See "-- Summary Compensation
Table" for option units granted under the Phantom Plan.

54
<PAGE> 55

AGGREGATED OPTION EXERCISES AND FISCAL YEAR-END OPTION VALUE TABLE

The following table provides information with respect to the unexercised
options to purchase the Common Stock held by the executive officers named in the
Summary Compensation Table at December 31, 1995. None of these executive
officers exercised any stock options during 1995.

AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END
OPTION/SAR VALUES

NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY
OPTIONS/SARS HELD AT OPTIONS/SARS AT
DECEMBER 31, 1995 DECEMBER 31, 1995 (1)
------------------ ---------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- --------------------------------------------------- ----------- ------------- ----------- --------------
<S> <C> <C> <C> <C>
Mark Andrews....................................... 83,550 126,600 $ 0 $ 0
Harold M. Korell................................... 42,687 62,250 0 0
John M. Hogan...................................... 28,687 31,250 0 0
Robert R. McBride, Jr.............................. 10,312 13,000 0 0
Steven L. Mueller.................................. 10,312 13,000 0 0
</TABLE>

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

(1) Based on the closing price of the Common Stock on the AMEX on December 31,
1995 of $11.375.

AGREEMENTS WITH CERTAIN EXECUTIVE OFFICERS AND KEY EMPLOYEES

After consultations by the Compensation Committee with its independent
compensation consultant regarding current practices by companies surveyed by
such consultant with respect to severance and employment agreements, upon the
Committee's recommendation, the Company has entered into new severance
agreements with eight of its executive officers and key employees and an
employment agreement with the Chief Executive Officer providing for certain
payments and other benefits upon the involuntary termination of the employment
of such persons, including their constructive termination following a Change in
Control, as defined in such agreements, of the Company. The severance and
employment agreements are intended to promote the retention of such persons in
the service of the Company by providing them with an extra measure of financial
security. The agreements provide that, upon involuntary termination, Mark
Andrews, the Chief Executive Officer, shall receive cash payments equal to three
times an amount equal to the sum of his base annual salary plus the average
amount of the bonuses paid to him in the last three fiscal years of the Company;
each of John Hogan and Harold Korell, Senior Vice Presidents, shall receive cash
payments equal to two times (three times in the event of a Change in Control) an
amount equal to the sum of their respective base annual salaries plus the
average amount of the bonuses paid to each individual in the last three fiscal
years of the Company; and each of Cindy Gerow, Harry Harper, Robert McBride,
Steve Mueller, Frank Murphy and Elliott Pew, Vice Presidents, shall receive cash
payments equal to one times (two times in the event of Change in Control) an
amount equal to the sum of their respective base annual salaries plus the
average of the bonuses paid to each individual in the last three fiscal years of
the Company. Such persons will also receive: (i) six months of medical and
dental insurance benefits (except disability coverage) at the expense of the
Company followed by 18 months of reimbursement for payments made by such persons
for medical and dental insurance continuation coverage in connection with rights
conferred under the Consolidated Omnibus Budget Reconciliation Act of 1985, (ii)
vesting of awards under the Company's stock compensation plans and Phantom Plan
and (iii) extension by six months of the exercise period for options. In
addition to the termination benefits described above, the employment agreement
with Mr. Andrews: (i) provides for an initial term of three years which
automatically renews for one-year periods unless the Board of Directors gives
written notice or the agreement is otherwise terminated in accordance with its
provisions, (ii) summarizes Mr. Andrews' duties, which may be changed with the
mutual consent of the Board of Directors and Mr. Andrews, (iii) sets his base
salary at $310,000, (iv) entitles him to participate in the bonus and other
benefits plans available to executives of the Company, (v) entitles him to
$2,500,000 of life insurance at the Company's expense and (vi) provides that Mr.
Andrews may, under certain circumstances, perform post-employment consulting
services and receive a reduced severance payment. The agreements do not provide
for any benefits in the event of a termination for cause. The severance
agreements provide for

55
<PAGE> 56

reduction of benefits under certain circumstances to avoid excise tax under
Section 4999 of the Internal Revenue Code of 1986, as amended.

COMPENSATION OF DIRECTORS

Each director, other than Mr. Andrews, received compensation of $2,000 per
year for his services as a member of the Board of Directors. Effective July
1995, this amount was increased to $10,000 per year payable quarterly beginning
with the third quarter of 1995. In addition, each director, other than Mr.
Andrews, receives $1,000 for each Board or Committee meeting attended and is
reimbursed for certain expenses incurred in attending meetings of the Board of
Directors and committees thereof. Each Committee chairman also receives $10,000
per year payable quarterly.

In addition, each director, other than Mr. Andrews, receives an initial
award of 2,500 stock options in his initial year of service, and receives annual
awards of 500 stock options, pursuant to the 1994 Stock Compensation Plan, for
as long as he remains a director.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

New York Life, the beneficial owner of 9.6% of the outstanding Common
Stock, as calculated pursuant to Rule 13d-3(d)(1) under the Exchange Act, and
one of its wholly owned subsidiaries were investors in the APPL Programs which
were dissolved in 1995. In connection with the APPL Consolidation, New York
Life, as an investor in the APPL Programs, acquired an aggregate of 379,229
shares of Common Stock in exchange for certain of its interests in the APPL
Programs and certain registration rights relating to such shares. Further, in
April 1994, New York Life established a $40.0 million nonrecourse secured credit
facility in favor of a wholly owned subsidiary of the Company to be used to
acquire interests in the APPL Programs. Under the terms of the facility, the
Company's subsidiary paid a commitment fee of $200,000 and financing fees of
1.25% of funds advanced and advances accrue interest at rates varying from 3% to
6% over the 30-day AI/PI commercial paper rate over the one-year term of
borrowings under the facility. During 1994, the Company's subsidiary borrowed
approximately $32.0 million under this facility and made interest and financing
fee payments aggregating $1.4 million. In early 1995, this facility was retired
using existing capacity on the Company's bank credit facility.

In mid-1990, the Company agreed to act as liquidator for New York Life in
connection with New York Life's investment in a partnership managed by another
oil company. In December 1993, the Company and New York Life's subsidiary, New
York Life Resources, Inc., formed Ancon Partnership Ltd., a Texas limited
partnership ("Ancon"), into which New York Life Resources, Inc., as a limited
partner, contributed these properties and the Company, as general partner,
purchased a 20% interest for $1.5 million. In May 1995, New York Life and
certain affiliates transferred certain of their limited partner interests in the
APPL Programs to Ancon. The Company acquired a 20% interest in these properties
for approximately $6.7 million in cash. The Company anticipates that New York
Life and various affiliates will contribute additional properties to Ancon. The
Company is obligated to purchase a 1% interest in such additional properties and
will have the option to purchase an additional 19% interest therein.

In connection with litigation relating to the NYLOG Programs (see
"Business -- Legal Proceedings"), the Company, a subsidiary of the Company and
NYLIFE entered into an indemnity agreement (the "Indemnity Agreement"), pursuant
to which NYLIFE agreed to indemnify the American Parties from and against any
and all judgments or settlements entered or reached in such litigation or any
subsequent lawsuits by investors in the NYLOG Programs, based on claims and
factual allegations substantially similar to those contained in the original
complaints filed. Pursuant to the Indemnity Agreement, NYLIFE assumed control of
the joint defense of this litigation at NYLIFE's expense. Additionally, pursuant
to the Indemnity Agreement, in connection with the liquidation sale of the
assets of the NYLOG Programs, the American Parties will be allocated only 5%
(which represents the American Parties' initial capital contribution percentage)
of revenues and net proceeds from the sale of properties effective from and
after February 1, 1996.

56
<PAGE> 57

In connection with the stock purchase program adopted by the Compensation
Committee pursuant to which members of management were granted Restricted Common
Stock and option units based, in the case of senior management, upon the number
of shares of Common Stock acquired, the Company permitted senior officers the
right to finance with the Company a portion of the shares acquired. In this
connection, Mr. Andrews financed a portion of the shares acquired through an
amortizing loan from the Company with an interest rate of 3.91% in the original
principal amount of $112,219. Mr. Andrews subsequently repaid his loan in early
1996.

During 1995, Nitze-Stagen & Company, Inc., of which Peter P. Nitze, a
director of the Company, is Chairman, performed financial consulting services
for the Company. The Company paid this company $20,000 for such services
rendered during 1995. During 1995, the Company paid John H. Moore, a director of
the Company, $11,250 for petroleum consulting services. O. Donaldson Chapoton, a
director of the Company through June 1995, is a partner in the law firm of Baker
& Botts, L.L.P. During 1995, Baker & Botts, L.L.P. received $285,000 from the
Company for legal services which it provided to the Company, although Mr.
Chapoton has no direct or indirect material interest in such amount.

57
<PAGE> 58

DESCRIPTION OF CAPITAL STOCK
PREFERRED STOCK

The Company's Restated Certificate of Incorporation (the "Restated
Certificate") authorizes the Company to issue, without any action on the part of
its stockholders, an aggregate of 100,000 shares of preferred stock, par value
$1.00 per share. The Board of Directors has authority to divide such preferred
stock into one or more series and has broad authority to fix and determine the
relative rights and preferences, including the voting rights, of the shares of
each such series. As of September 30, 1996, an aggregate of 85,000 shares of
preferred stock of the Company had been reserved for issuance upon exercise of
the Rights described below under "-- Stockholder Rights Plan."

In addition, the Company's currently outstanding Convertible Preferred
Stock represents 4,000 shares of preferred stock. In December 1993, the Company
privately placed 800,000 Depositary Shares, each representing a 1/200 interest
in a share of the Convertible Preferred Stock. The Convertible Preferred Stock
has a stated value of $5,000 per share, with dividends payable quarterly at the
annual rate of $450 per share. The Convertible Preferred Stock is convertible at
any time at the option of the holders into shares of Common Stock at a
conversion price of $15.00 per share, subject to adjustment in certain
circumstances. Beginning December 31, 1997, the Convertible Preferred Stock will
be redeemable at the option of the Company, in whole or in part, at any time.
The initial redemption price is $5,270 per share, declining ratably on December
31 of each year to a redemption price of $5,000 per share on and after December
31, 2003, plus accrued and unpaid dividends.

The Convertible Preferred Stock has a special conversion right that becomes
effective upon the occurrence of certain types of significant transactions
affecting ownership or control of the Company. If the special conversion right
becomes effective, the then-prevailing conversion price would be reduced to the
market value of the Common Stock, not to be reduced below a minimum conversion
price of $11.25 per share of Common Stock.

In the event of liquidation, the holders of the Convertible Preferred Stock
will receive a preferred liquidation payment equal to $5,000 per share plus
accrued and unpaid dividends. The holders of the Convertible Preferred Stock are
entitled to vote on all matters submitted to a vote of the holders of the Common
Stock. Each holder of a share of Convertible Preferred Stock is entitled to one
vote for each share of Common Stock into which a share of Convertible Preferred
Stock could be converted. The holders of the Convertible Preferred Stock are
entitled to separate class voting in certain circumstances, including (i) if
dividends on such stock are in arrears for six fiscal quarters, (ii) the
creation of any class or series of stock ranking prior to the Convertible
Preferred Stock and (iii) any amendment or alteration of the Company's Restated
Certificate that adversely affects the preferences, special rights or powers of
the Convertible Preferred Stock.

COMMON STOCK

As of September 30, 1996, the Company was authorized to issue 50,000,000
shares of Common Stock. As of September 30, 1996, an aggregate of 11,807,741
shares were outstanding and an aggregate of 4,357,423 shares were reserved for
issuance upon exercise of outstanding options and warrants and upon conversion
(including conversion pursuant to special conversion rights) of the Convertible
Preferred Stock. All shares of Common Stock have equal rights to participate in
dividends and, in the event of liquidation, assets, subject to all preferences
established with respect to the Company's preferred stock. Each holder of Common
Stock is entitled to one vote for each share held on all matters submitted to a
vote of stockholders. The Common Stock does not have cumulative voting rights.
Shares of Common Stock carry no conversion, preemptive or subscription rights
and are not subject to redemption. All outstanding shares of Common Stock are
fully paid and nonassessable. The Company currently pays no dividends on Common
Stock but is authorized to pay such dividends when, as and if declared by the
Board of Directors. Dividends may be declared in the discretion of the Board of
Directors from funds legally available therefor, subject to restrictions in the
Company's Credit Agreement and the agreements relating to its Subordinated
Notes.

The transfer agent and registrar of the Common Stock is KeyCorp Shareholder
Services, Inc., 1201 Elm Street, Dallas, Texas 75270.

58
<PAGE> 59

STOCKHOLDER RIGHTS PLAN

General. In September 1993, the Board of Directors declared a distribution
of one right ("Right") for each outstanding share of Common Stock outstanding to
stockholders of record at the close of business on October 8, 1993 and for each
share of Common Stock issued by the Company (including shares issued upon
conversion of the Convertible Preferred Stock) thereafter and prior to the
Distribution Date (as described below). Each Right entitles the registered
holder to purchase from the Company one one-thousandth of a share (a "Unit") of
Series B Preferred Stock, par value $1.00 per share (the "Series B Preferred
Stock"), at a purchase price of $7.50 per Unit, subject to adjustment (the
"Purchase Price"). The following summary description of the Rights does not
purport to be complete and is qualified in its entirety by reference to the
Rights Agreement between the Company and Society National Bank dated September
28, 1993 (the "Rights Agreement"), as supplemented by the Amendment to Rights
Agreement dated August 3, 1994, copies of which have been filed with the
Commission as exhibits to the Company's Current Reports on Form 8-K dated
September 28, 1993 and August 31, 1994, respectively.

The Rights Agreement. Initially, a Right will attach to each certificate
representing a share of outstanding Common Stock, and no separate certificates
for the Rights ("Rights Certificates") will be distributed. Each Right will
separate from the Common Stock and a "Distribution Date" will occur upon the
earlier of (i) ten business days following a public announcement that a Person
(as such term is defined in the Rights Agreement) or group of affiliated or
associated persons (other than the Company, any subsidiary of the Company or any
employee benefit plan of the Company or such subsidiary or certain former
investors in certain of the Company's institutional oil and gas programs by
virtue of their exchange of interests in such programs for Common Stock) (an
"Acquiring Person") has acquired, obtained the right to acquire or otherwise
obtained beneficial ownership of 15% or more of the then outstanding shares of
Common Stock (the date of the announcement being the "Stock Acquisition Date"),
and (ii) ten business days (or such later date as may be determined by action of
the Board of Directors before any person becomes an Acquiring Person) following
the commencement of a tender offer or exchange offer that would result in a
person or group beneficially owning 30% or more of the then outstanding shares
of Common Stock.

The Rights are not exercisable until the Distribution Date and will expire
at the close of business on the tenth anniversary of the Rights Agreement unless
earlier redeemed by the Company as described below.

As soon as practicable after the Distribution Date, Rights Certificates
will be mailed to holders of record of Common Stock as of the close of business
on the Distribution Date and, thereafter, the separate Rights Certificates alone
will represent the Rights.

In the event that (i) the Company is the surviving corporation in a merger
with an Acquiring Person and shares of Common Stock remain outstanding, (ii) a
Person becomes the beneficial owner of 15% or more of the then outstanding
shares of Common Stock, (iii) an Acquiring Person engages in one or more "self-
dealing" transactions as set forth in the Rights Agreement or (iv) during such
time as there is an Acquiring Person, an event occurs that results in such
Acquiring Person's ownership interest being increased by more than 1% (e.g., by
means of a reverse stock split or recapitalization), then, in each such case,
each holder of a Right will thereafter have the right to receive, upon exercise,
Units of Series B Preferred Stock (or, in certain circumstances, Common Stock,
cash, property or other securities of the Company) having a value equal to two
times the amount payable upon exercise of the Right. The amount payable upon
exercise is the then current Purchase Price multiplied by the number of Units of
Series B Preferred Stock issuable upon exercise of a Right immediately prior to
the events described in this paragraph. Notwithstanding any of the foregoing,
following the occurrence of any of the events set forth in this paragraph, all
Rights that are, or were (under certain circumstances specified in the Rights
Agreement), beneficially owned by any Acquiring Person will be null and void.

In the event that at any time following the Stock Acquisition Date, (i) the
Company is acquired in a merger or other business combination transaction and
the Company is not the surviving corporation (other than a merger described in
the preceding paragraph), (ii) any Person consolidates or merges with the
Company and all or part of the Common Stock is converted or exchanged for
securities, cash or property of any other Person or (iii) 50% or more of the
Company's assets or earning power is sold or transferred, each holder of a Right
(except Rights that previously have been voided as described above) will
thereafter have the

59
<PAGE> 60

right to receive, upon exercise, common stock of the Acquiring Person having a
value equal to two times the amount payable upon exercise of the Right.

The amount payable, and the number of Units of Series B Preferred Stock
issuable, upon exercise of the Rights is subject to adjustment from time to time
to prevent dilution upon the occurrence of certain events.

At any time until ten business days following the Stock Acquisition Date, a
majority of the Independent Directors (as such term is defined in the Rights
Agreement) may redeem the Rights in whole, but not in part, at a price of $.10
per Right, subject to adjustment upon the occurrence of certain events (the
"Redemption Price"), payable, at the election of such majority of the
Independent Directors, in cash or shares of Common Stock. Immediately upon the
action of a majority of Independent Directors ordering the redemption of the
Rights, 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 stockholder of the Company, including, without limitation, the right
to vote or to receive dividends. Holders of Common Stock or of Convertible
Preferred Stock may, depending upon the circumstances, recognize taxable income
in the event that the Rights become exercisable for Units of Series B Preferred
Stock (or other consideration).

Description of the Series B Preferred Stock. The Units of Series B
Preferred Stock that may be acquired upon exercise of the Rights will be
nonredeemable and subordinate to any other shares of preferred stock that may be
issued by the Company. Each Unit of Series B Preferred Stock will have a minimum
preferential quarterly dividend of $0.01 per Unit or any higher per share
dividend declared on the Common Stock.

The holder of each Unit of Series B Preferred Stock will be entitled to one
vote for each Unit held, voting together with the Common Stock. The holders of
Units of Series B Preferred Stock, voting as a separate class, will be entitled
to elect two directors if dividends on the Series B Preferred Stock are in
arrears for six fiscal quarters.

In the event of any merger, consolidation or other transaction in which
shares of Common Stock are exchanged, each Unit of Series B Preferred Stock will
be entitled to receive the per share amount paid in respect of each share of
Common Stock. In the event of liquidation, the holder of a Unit of Series B
Preferred Stock will receive a preferred liquidation payment equal to the
greater of $0.10 per Unit plus accrued and unpaid dividends and the per share
amount paid in respect of a share of Common Stock. Certain rights of the holders
of the Preferred Stock, including voting rights, rights upon liquidation and
rights upon merger, consolidation or other transactions in which shares of
Common Stock are exchanged, are subject to adjustment upon the occurrence of
certain events.

PROVISIONS OF THE COMPANY'S BYLAWS

Certain provisions of the Company's Bylaws establish time periods during
which appropriate stockholder proposals must be delivered to the Company for
consideration at special and annual meetings called by the Company. The Bylaws
provide, among other things, that (i) only the Board of Directors may call
special meetings of stockholders, (ii) stockholders making nominations for the
Board of Directors at, or bringing other business before, an annual meeting of
stockholders must provide timely written notice to the Company thereof (timely
notice being required to be no later than 60 days before the first anniversary
of the preceding year's annual meeting or, in the event the date of an annual
meeting is advanced by more than 30 days, or delayed by more than 60 days, from
such anniversary date, no later than 60 days before the date of such annual
meeting or ten days following the day on which the date of such meeting is
publicly announced) and (iii) stockholders making nominations for the Board of
Directors at a special meeting of stockholders must provide timely written
notice to the Company thereof (timely notice being required to be no later than
60 days before such special meeting or ten days following the day on which the
date of such special meeting is publicly announced).

WARRANTS

As of September 30, 1996, there were warrants outstanding to purchase an
aggregate of up to approximately 1.5 million shares of Common Stock. In December
1991, the Company issued warrants to certain institutional investors
contemporaneously with the issuance of its Subordinated Notes (the
"Institutional Warrants"). The Institutional Warrants granted the right to
purchase approximately 1.2 million shares

60
<PAGE> 61

(as adjusted for subsequent events) of Common Stock at an exercise price of
$15.53 per share, subject to adjustment, on or before December 30, 2004. In
connection with an acquisition of Common Stock in September 1992, Prudential
Insurance acquired warrants to purchase approximately 0.3 million shares (as
adjusted) of Common Stock at an exercise price of $22.19 per share, subject to
adjustment, on or before April 30, 1999 (the "Prudential Warrants" and,
collectively with the Institutional Warrants, the "Warrants").

The Warrants contain certain provisions for adjustment of exercise prices
in certain events, including sales of Common Stock at less than the exercise
price or fair market value thereof, stock dividends, stock splits,
reorganizations, reclassifications and mergers.

Holders of the Warrants are also entitled to certain registration rights
with respect to Common Stock issued upon the exercise thereof.

The Company may at its option redeem (i) any or all of the outstanding
Institutional Warrants for cash on or after December 30, 1996 at $10.35 per
share of Common Stock issuable upon the exercise of such warrants, subject to
adjustment, and (ii) all of the outstanding Prudential Warrants at any time
after October 1, 1994 at the exercise price in effect on the date of redemption,
provided in each case that the Common Stock has traded at specified prices above
the then current exercise price for a specified period.

LIMITATION ON DIRECTORS' LIABILITY

Delaware law authorizes corporations to limit or eliminate the personal
liability of directors to corporations and their stockholders for monetary
damages for breach of directors' fiduciary duty of care. The Restated
Certificate limits the liability of directors of the Company to the Company or
its stockholders (in their capacity as directors but not in their capacity as
officers) to the fullest extent permitted by Delaware law. Specifically,
directors of the Company will not be personally liable for monetary damages for
breach of a director's fiduciary duty as a director, except for liability (i)
for any breach of the director's duty of loyalty to the Company or its
stockholders, (ii) for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of law, (iii) for unlawful
payments of dividends or unlawful stock repurchases or redemptions as provided
in Section 174 of the Delaware General Corporation Law ("DGCL") or (iv) for any
transaction from which the director derived an improper personal benefit.

The inclusion of this provision in the Restated Certificate may have the
effect of reducing the likelihood of derivative litigation against directors and
may discourage or deter stockholders or management from bringing a lawsuit
against directors for breach of their duty of care, even though such an action,
if successful, might otherwise have benefited the Company and its stockholders.

SECTION 203 OF THE DELAWARE GENERAL CORPORATION LAW

The Company is a Delaware corporation and is subject to Section 203 of the
DGCL. Generally, Section 203 prohibits a publicly held Delaware corporation from
engaging in a "business combination" with an "interested stockholder" for a
period of three years after the date of the transaction in which the person
became an interested stockholder, unless (i) prior to such date, either the
business combination or such transaction is approved by the board of directors
of the corporation, (ii) upon consummation of the transaction that resulted in
the stockholder becoming an interested stockholder, the interested stockholder
owns at least 85% of the outstanding voting stock or (iii) on or after such
date, the business combination is approved by the board and by the affirmative
vote of at least 66 2/3% of the outstanding voting stock that is not owned by
the interested stockholder. A "business combination" includes mergers, asset
sales and other transactions resulting in a financial benefit to the interested
stockholder. An "interested stockholder" is a person who, together with
affiliates and associates, owns (or within three years, did own) 15% or more of
the corporation's outstanding voting stock.

LIMITATION ON CHANGES IN CONTROL

The Rights and Rights Agreement, certain provisions of the Company's Bylaws
and the provisions of Section 203 of the DGCL could have the effect of delaying,
deferring or preventing a change in control of the Company. This could be the
case, notwithstanding that a majority of the stockholders might benefit from
such a change in control or offer.

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<PAGE> 62

UNDERWRITING

The Underwriters named below (the "Underwriters"), for whom Prudential
Securities Incorporated, Dillon, Read & Co. Inc. and A. G. Edwards & Sons, Inc.
are acting as representatives (the "Representatives"), have severally agreed,
subject to the terms and conditions contained in the Underwriting Agreement, to
purchase from the Company and the Selling Stockholders the number of shares of
Common Stock set forth below opposite their respective names:

<TABLE>
<CAPTION>
NUMBER
OF
UNDERWRITER SHARES
----------------------------------------------------------------- --------
<S> <C>
Prudential Securities Incorporated............................... 1,053,053
Dillon, Read & Co. Inc. ......................................... 1,053,051
A.G. Edwards & Sons, Inc. ....................................... 1,053,051
Lehman Brothers Inc. ............................................ 109,700
J.P. Morgan Securities Inc. ..................................... 109,700
Nesbitt Burns Securities Inc. ................................... 109,700
Oppenheimer & Co., Inc. ......................................... 109,700
First Albany Corporation ........................................ 54,850
Hanifen, Imhoff Inc. ............................................ 54,850
Jefferies & Company, Inc. ....................................... 54,850
Paribas Corporation.............................................. 54,850
Starr Securities, Inc. .......................................... 54,850
Van Kasper & Company............................................. 54,850
---------
Total.................................................. 3,927,055
=========
</TABLE>

The Company and the Selling Stockholders are obligated to sell, and the
Underwriters are obligated to purchase, all of the shares of Common Stock
offered hereby if any are purchased.

The Underwriters, through their Representatives, have advised the Company
and the Selling Stockholders that they propose to offer the Common Stock
initially at the public offering price set forth on the cover page of this
Prospectus; that the Underwriters may allow to selected dealers a concession of
$0.40 per share; and that such dealers may reallow a concession of $0.10 per
share to certain other dealers. After the public offering, the offering price
and the concessions may be changed by the Representatives.

The Company and one of the Selling Stockholders have granted to the
Underwriters options, exercisable for 30 days from the date of this Prospectus,
to purchase up to 532,174 and 56,884 additional shares of Common Stock,
respectively, at the initial public offering price, less underwriting discounts
and commissions, as set forth on the cover page of this Prospectus. The
Underwriters may exercise such options solely for the purpose of covering
over-allotments incurred in the sale of the shares of Common Stock offered
hereby. To the extent such options to purchase are exercised, each Underwriter
will become obligated, subject to certain conditions, to purchase approximately
the same percentage of such additional shares as the number of shares set forth
next to such Underwriter's name in the preceding table bears to 3,927,055.

The Company and the Selling Stockholders have agreed to indemnify the
several Underwriters or contribute to losses arising out of certain liabilities,
including liabilities under the Securities Act. Prudential Insurance, one of the
Selling Stockholders, is an affiliate of Prudential Securities Incorporated. See
"Selling Stockholders."

The Company, its directors and executive officers, the Selling Stockholders
and certain other stockholders holding an aggregate of approximately 5,300,000
shares of Common Stock (exclusive of shares of Common Stock being sold by the
Selling Stockholders) have agreed that they will not, directly or indirectly,
offer, sell, offer to sell, contract to sell, pledge, grant any option to
purchase or otherwise sell or dispose (or announce any offer, sale, offer of
sale, contract of sale, pledge, grant of any option to purchase or other sale or
disposition) of any shares of Common Stock or any securities convertible into,
or exchangeable or exercisable for, shares of Common Stock, without the prior
written consent of Prudential Securities Incorporated on

62
<PAGE> 63

behalf of the Underwriters, for a period of 90 days after the date of this
Prospectus, except for shares offered pursuant to the Offering and issuances
pursuant to the exercise of options granted under employee benefit plans
existing as of the date of this Prospectus or pursuant to the terms of
convertible securities or warrants of the Company outstanding as of the date of
this Prospectus.

JP Morgan Securities Incorporated, Nesbitt Burns Securities Incorporated
and Paribas Corporation, underwriters of the Offering, are affiliates of Morgan
Guaranty Trust Company of New York, Bank of Montreal and Banque Paribas,
respectively, lenders under the Company's Credit Agreement. Walter J.P. Curley,
Jr., a director of the Company, is also a director of Paribas Corporation. A
portion of the net proceeds of the Offering will be used to repay amounts
outstanding under the Credit Agreement. See "Use of Proceeds."

LEGAL MATTERS

Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Company by Baker & Botts, L.L.P., Houston,
Texas and Patterson, Belknap, Webb & Tyler LLP, New York, New York and for the
Underwriters by Andrews & Kurth L.L.P., Houston, Texas.

EXPERTS

The audited consolidated financial statements of the Company included in
this Prospectus have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their report with respect thereto, and are included
herein in reliance upon the authority of said firm as experts in giving said
report.

The statement of oil and gas revenues and direct lease operating expenses
of the Zilkha II Properties for the year ended December 31, 1995, and the
statements of oil and gas revenues and direct lease operating expenses of the
Zilkha I Properties for each of the years in the three-year period ended
December 31, 1995, have been included herein and in the registration statement
in reliance upon the reports of KPMG Peat Marwick LLP, independent certified
public accountants, appearing elsewhere herein, and upon the authority of said
firm as experts in accounting and auditing.

The letter reports of Netherland, Sewell & Associates, Inc. and William M.
Cobb & Associates, Inc. set forth in Appendix A have been included herein in
reliance upon the authority of each such firm as experts in estimating proved
oil and gas reserves.

AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Exchange
Act and, in accordance therewith, files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information filed by the Company may be inspected at, and upon payment of the
Commission's customary charges copies may be obtained from, the public reference
facilities maintained by the Commission at 450 Fifth Street, N.W., Judiciary
Plaza, Washington, D.C. 20549. Such reports, proxy statements and other
information are also available for inspection and copying at prescribed rates at
the Commission's regional offices at Northwest Atrium Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60661-2511; and 7 World Trade Center, New
York, New York 10048. The Commission maintains an Internet web site that
contains reports, proxy and information statements and other information
regarding registrants that file electronically with the Commission
(http://www.sec.gov). The Common Stock is listed on the AMEX. Documents filed by
the Company may also be inspected at the offices of the AMEX, 86 Trinity Place,
New York, New York 10006.

The Company has filed a Registration Statement on Form S-1 (the
"Registration Statement") under the Securities Act with the Commission with
respect to the Offering. This Prospectus, filed as a part of the Registration
Statement, does not contain all of the information set forth in the Registration
Statement, or the exhibits and schedules thereto, in accordance with the rules
and regulations of the Commission, and reference is hereby made to such omitted
information. Statements made in this Prospectus concerning any document

63
<PAGE> 64

filed as an exhibit to the Registration Statement are not necessarily complete,
and in each instance reference is made to such exhibit for a complete statement
of its provisions. The Registration Statement and the exhibits and schedules
thereto may be inspected at, and upon payment of the Commission's customary
charges copies may be obtained from, the public reference facilities maintained
by the Commission as provided in the preceding paragraph.

64
<PAGE> 65

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are abbreviations and definitions of terms commonly used in
the oil and gas industry and this Prospectus. Unless otherwise indicated in this
Prospectus, natural gas volumes are stated at the legal pressure base of the
state or area in which the reserves are located and at 60 degrees Fahrenheit.
BOEs are determined using the ratio of six Mcf of natural gas to one Bbl of oil.

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

"BCF" means billion cubic feet of natural gas.

"BOE" means barrels of oil equivalent.

"BOEPD" means barrels of oil equivalent per day.

"BBTU" means one billion British Thermal Units.

"BTU" or "BRITISH THERMAL UNIT" means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit.

"COMPLETION" means the installation of permanent equipment for the
production of oil or gas.

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

"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.

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

"MBBLS" means thousand of barrels of oil.

"MBOE" means thousand barrels of oil equivalent.

"MCF" means thousand cubic feet of natural gas.

"MMBBLS" means million barrels of oil.

"MMBOE" means million barrels of oil equivalent.

"MMBTU" means one million British Thermal Units.

"MMCF" means million cubic feet of natural gas.

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

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

"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.

"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.

65
<PAGE> 66

"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
escalations based upon future conditions.

i. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation testing. 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 reserves"; (b) crude oil, natural gas
and natural gas liquids the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics or
economic factors; (c) crude oil, natural gas and natural gas liquids that
may occur in undrilled prospects; and (d) crude oil, natural gas and
natural gas liquids that may be recovered from oil shales, coal, gilsonite
and other such 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 shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.

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

"RESERVES" means proved reserves.

"SEC-10 VALUE" means the present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance with
Commission guidelines, net of estimated production and future development costs,
using prices and costs as of the date of estimation without future escalation,
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%.

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

"2-D SEISMIC" or "2-D DATA" means seismic data that are acquired and
processed to yield a two-dimensional cross section of the subsurface.

"WATERFLOOD" means the injection of water into a reservoir to fill pores
vacated by produced fluids, thus maintaining reservoir pressure and assisting
production.

"WORKING INTEREST" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will

66
<PAGE> 67

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 87.5% of the production.

"WORKOVER" means operations on a producing well to restore or increase
production.

67
<PAGE> 68

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Consolidated Financial Statements of American Exploration Company and Subsidiaries
Report of Independent Public Accountants........................................... F- 2
Consolidated Balance Sheets as of December 31, 1994 and 1995 and as of September
30, 1996........................................................................ F- 3
Consolidated Statements of Operations for the Three Years in the Period Ended
December 31, 1995 and for the Nine Months Ended September 30, 1995 and 1996..... F- 4
Consolidated Statements of Cash Flows for the Three Years in the Period Ended
December 31, 1995 and for the Nine Months Ended September 30, 1995 and 1996..... F- 5
Consolidated Statements of Stockholders' Equity for the Three Years in the Period
Ended December 31, 1995 and the Nine Months Ended September 30, 1996............ F- 6
Notes to Consolidated Financial Statements......................................... F- 7
Supplemental Information on Oil and Gas Producing Activities....................... F-33
The Zilkha I Properties -- Statements of Oil and Gas Revenues and Direct Lease
Operating Expenses
Independent Auditors' Report....................................................... F-37
Statements of Oil and Gas Revenues and Direct Lease Operating Expenses for the
Years Ended December 31, 1993, 1994 and 1995 and the Period January 1, 1996
through February 29, 1996 (unaudited)........................................... F-38
Notes to Statements of Oil and Gas Revenues and Direct Lease Operating Expenses.... F-39
The Zilkha II Properties -- Statements of Oil and Gas Revenues and Direct Lease
Operating Expenses
Independent Auditors' Report....................................................... F-42
Statements of Oil and Gas Revenues and Direct Lease Operating Expenses for the Year
Ended December 31, 1995 and the Period January 1, 1996 through June 30, 1996
(unaudited)..................................................................... F-43
Notes to Statements of Oil and Gas Revenues and Direct Lease Operating Expenses.... F-44
</TABLE>

F-1
<PAGE> 69

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors,
American Exploration Company:

We have audited the accompanying consolidated balance sheets of American
Exploration Company (a Delaware corporation) and subsidiaries as of December 31,
1995 and 1994, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three 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.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of American
Exploration Company and subsidiaries as of December 31, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1995, in conformity with generally accepted
accounting principles.

As explained in Note 1 to the consolidated financial statements, in 1994,
the Company changed its method of accounting for impairments of proved oil and
gas properties.

ARTHUR ANDERSEN LLP

Houston, Texas
March 22, 1996

F-2
<PAGE> 70

CONSOLIDATED BALANCE SHEETS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT FOR SHARE AMOUNTS)

<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER
---------------------- 30,
1994 1995 1996
--------- --------- -----------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and temporary cash investments...................... $ 9,973 $ 7,496 $ 6,780
Accounts receivable...................................... 10,652 14,520 11,203
Receivable from partnerships............................. 4,488 429 --
Assets held for sale..................................... -- -- 14,384
Other current assets..................................... 1,014 966 2,158
--------- --------- -----------
Total current assets............................. 26,127 23,411 34,525
--------- --------- -----------
Property, plant and equipment:
Oil and gas properties, based on successful efforts
accounting............................................ 343,453 292,027 337,881
Other property and equipment............................. 12,530 13,036 13,365
--------- --------- -----------
355,983 305,063 351,246
Less: Accumulated depreciation, depletion and
amortization.......................................... 160,578 154,646 155,396
--------- --------- -----------
Property, plant and equipment, net.................... 195,405 150,417 195,850
--------- --------- -----------
Other assets............................................... 2,362 2,202 2,988
--------- --------- -----------
Total assets..................................... $ 223,894 $ 176,030 $ 233,363
========= ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable......................................... $ 14,391 $ 18,149 $ 15,670
Payable to partnerships.................................. -- -- 1,678
Accrued liabilities...................................... 15,838 16,953 18,800
--------- --------- -----------
Total current liabilities........................ 30,229 35,102 36,148
--------- --------- -----------
Long-term debt............................................. 69,582 40,000 105,000
--------- --------- -----------
Note payable to related party.............................. 31,128 -- --
--------- --------- -----------
Other liabilities.......................................... 5,245 6,448 4,709
--------- --------- -----------
Commitments and contingencies (Note 14)....................
Stockholders' equity:
Preferred stock, $1.00 par value; authorized: 100,000
shares (1994, 1995 and 1996); issued and outstanding:
Convertible Preferred Stock, 4,000 shares (1994, 1995
and 1996)............................................. 4 4 4
Common stock, $.05 par value; authorized: 50,000,000
shares (1994, 1995 and 1996); issued: 11,477,500
shares (1994), 11,812,483 shares (1995) and 11,807,741
shares (1996); outstanding: 11,468,313 shares (1994),
11,812,483 shares (1995) and 11,807,741 shares
(1996)................................................ 574 591 590
Additional paid-in capital............................... 272,817 276,713 276,658
Accumulated deficit...................................... (184,676) (182,543) (189,664)
Treasury stock, at cost; 9,187 shares (1994)............. (342) -- --
Unearned compensation.................................... (525) (219) (79)
Notes receivable from officers........................... (142) (66) (3)
--------- --------- -----------
Total stockholders' equity............................ 87,710 94,480 87,506
--------- --------- -----------
Total liabilities and stockholders' equity....... $ 223,894 $ 176,030 $ 233,363
========= ========= =========
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-3
<PAGE> 71

CONSOLIDATED STATEMENTS OF OPERATIONS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
------------------------------- ------------------
1993 1994 1995 1995 1996
-------- -------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales.......................... $ 49,589 $ 50,033 $70,768 $55,049 $52,263
Gain (loss) on sales of oil and gas
properties.............................. (6,894) 1,110 10,230 9,674 801
Other revenues, net........................ 15,463 216 936 678 111
-------- -------- ------- ------- -------
Total revenues..................... 58,158 51,359 81,934 65,401 53,175
-------- -------- ------- ------- -------
Costs and expenses:
Production and operating................... 15,998 21,302 24,515 19,079 15,421
Depreciation, depletion and amortization... 23,635 29,616 30,726 22,446 20,871
General and administrative................. 7,413 10,035 7,472 4,683 4,450
Taxes other than income.................... 4,601 5,710 5,760 4,413 4,254
Exploration................................ 7,554 2,559 4,826 3,269 9,152
Impairment................................. 10,975 33,570 1,822 43 1,841
-------- -------- ------- ------- -------
Total costs and expenses........... 70,176 102,792 75,121 53,933 55,989
-------- -------- ------- ------- -------
Income (loss) from operations................ (12,018) (51,433) 6,813 11,468 (2,814)
-------- -------- ------- ------- -------
Other income (expense):
Interest expense........................... (6,847) (6,638) (5,481) (4,853) (2,894)
Other income (expense), net................ 184 (2,619) 24 (59) (63)
-------- -------- ------- ------- -------
Total other expense................ (6,663) (9,257) (5,457) (4,912) (2,957)
-------- -------- ------- ------- -------
Income (loss) before income taxes and
extraordinary item......................... (18,681) (60,690) 1,356 6,556 (5,771)
Income tax benefit (provision)............... (505) 455 121 (46) --
-------- -------- ------- ------- -------
Income (loss) before extraordinary item...... (19,186) (60,235) 1,477 6,510 (5,771)
Extraordinary gain on extinguishment of
debt....................................... -- 5,419 2,456 2,456 --
-------- -------- ------- ------- -------
Net income (loss)............................ (19,186) (54,816) 3,933 8,966 (5,771)
Preferred stock dividends.................... (75) (1,800) (1,800) (1,350) (1,350)
-------- -------- ------- ------- -------
Net income (loss) to common stock............ $(19,261) $(56,616) $ 2,133 $ 7,616 $(7,121)
======== ======== ======= ======= =======
Net income (loss) per common share:
Primary and fully diluted:
Loss before extraordinary item.......... $ (2.77) $ (7.70) $ (0.03) $ 0.43 $ (0.60)
Extraordinary item...................... -- 0.68 0.21 0.21 --
-------- -------- ------- ------- -------
Net income (loss) per common
share............................ $ (2.77) $ (7.02) $ 0.18 $ 0.64 $ (0.60)
======== ======== ======= ======= =======
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-4
<PAGE> 72

CONSOLIDATED STATEMENTS OF CASH FLOWS
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS)

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
-------------------------------- --------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)....................... $(19,186) $(54,816) $ 3,933 $ 8,966 $ (5,771)
Adjustments to arrive at net cash
provided by operating activities:
Depreciation, depletion and
amortization....................... 23,635 29,616 30,726 22,446 20,871
Loss (gain) on sales of oil and gas
properties......................... 6,894 (1,110) (10,230) (9,674) (801)
Exploration expense.................. 4,720 1,888 4,760 3,208 9,152
Impairment expense................... 10,975 33,570 1,822 43 1,841
Extraordinary gain................... -- (5,419) (2,456) (2,456) --
Other, net........................... (150) 2,909 759 531 343
Changes in operating working capital:
Accounts receivable.................. 411 (2,899) (574) (1,971) 5,216
Other current assets................. 920 (320) (144) (472) 214
Accounts payable and accrued
liabilities........................ (1,939) 1,874 5,760 2,457 (3,053)
Other operating......................... (1,563) 2,454 (1,051) 659 (903)
-------- -------- -------- -------- --------
Net cash provided by operating
activities...................... 24,717 7,747 33,305 23,737 27,109
-------- -------- -------- -------- --------
Cash flows from investing activities:
Acquisition of oil and gas properties... (4,273) (28,387) (15,972) (11,087) (62,832)
Development and exploration
expenditures......................... (18,675) (20,944) (27,480) (20,142) (29,284)
Other capital expenditures.............. (1,219) (558) (763) -- --
Sales of oil and gas properties......... 35,666 2,638 63,488 62,218 1,194
Other investing......................... (2,488) (3,683) 2,308 1,585 (415)
-------- -------- -------- -------- --------
Net cash provided by (used in)
investing activities............ 9,011 (50,934) 21,581 32,574 (91,337)
-------- -------- -------- -------- --------
Cash flows from financing activities:
Bank debt borrowings.................... 12,500 23,000 50,500 43,500 74,000
Bank debt repayments.................... (60,000) (1,500) (73,500) (69,500) (9,000)
Borrowings under bridge credit
facility............................. -- 32,078 -- -- --
Repayments under bridge credit
facility............................. -- (950) (31,128) (31,128) --
Repayments of other debt................ (4,001) (8,622) (1,141) -- --
Issuance of equity securities........... 21,348 2,100 -- -- --
Preferred stock dividends............... (75) (1,800) (1,800) (1,350) (1,350)
Debt and equity issuance costs and
other................................ (2,161) (3,382) (294) (1,363) (138)
-------- -------- -------- -------- --------
Net cash provided by (used in)
financing activities............ (32,389) 40,924 (57,363) (59,841) 63,512
-------- -------- -------- -------- --------
Net increase (decrease) in cash and
temporary cash investments.............. 1,339 (2,263) (2,477) (3,530) (716)
Cash and temporary cash investments at
beginning of period..................... 10,897 12,236 9,973 9,973 7,496
-------- -------- -------- -------- --------
Cash and temporary cash investments at end
of period............................... $ 12,236 $ 9,973 $ 7,496 $ 6,443 $ 6,780
======== ======== ======== ======== ========
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-5
<PAGE> 73

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
(IN THOUSANDS)
<TABLE>
<CAPTION>
CONVERTIBLE ADDITIONAL
PREFERRED COMMON PAID-IN ACCUMULATED
STOCK STOCK CAPITAL DEFICIT
------------ ------- ---------- -----------
<S> <C> <C> <C> <C>
Balance, December 31, 1992........................................... $ -- $ 348 $ 195,674 $ (108,799)
Sale of convertible preferred stock................................ 4 -- 19,996 --
Sale of common stock............................................... -- 5 1,435 --
Stock issuance costs............................................... -- -- (1,508) --
Dividends on preferred stock ($18.75 per share).................... -- -- -- (75)
Unearned compensation on restricted common stock................... -- -- -- --
Amortization of unearned compensation.............................. -- -- -- --
Issuance of notes receivable from officers......................... -- -- -- --
Sale of Canadian companies......................................... -- -- -- --
Translation adjustment............................................. -- -- -- --
Net loss........................................................... -- -- -- (19,186)
------------ ------- ---------- -----------
Balance, December 31, 1993........................................... 4 353 215,597 (128,060)
Issuance of shares in APPL Consolidation........................... -- 213 56,017 --
Sale of common stock............................................... -- 8 2,092 --
Stock issuance costs............................................... -- -- (889) --
Dividends on preferred stock ($450.00 per share)................... -- -- -- (1,800)
Amortization of unearned compensation.............................. -- -- -- --
Repayments of notes receivable from officers....................... -- -- -- --
Net loss........................................................... -- -- -- (54,816)
------------ ------- ---------- -----------
Balance, December 31, 1994........................................... 4 574 272,817 (184,676)
Issuance of shares in APPL Consolidation........................... -- 17 4,309 --
Reverse stock split costs.......................................... -- -- (71) --
Cancellation of treasury shares.................................... -- -- (342) --
Dividends on preferred stock ($450.00 per share)................... -- -- -- (1,800)
Amortization of unearned compensation.............................. -- -- -- --
Repayments of notes receivable from officers....................... -- -- -- --
Net income......................................................... -- -- -- 3,933
------------ ------- ---------- -----------
Balance, December 31, 1995........................................... 4 591 276,713 (182,543)
Cancellation of shares............................................. -- (1) (55) --
Dividends on preferred stock ($450.00 per share)................... -- -- -- (1,350)
Amortization of unearned compensation.............................. -- -- -- --
Repayments of notes receivable from officers....................... -- -- -- --
Net loss........................................................... -- -- -- (5,771)
------------ ------- ---------- -----------
Balance, September 30, 1996 (Unaudited).............................. $ 4 $ 590 $ 276,658 $ (189,664)
============ ======= ========== ===========

<CAPTION>
FOREIGN NOTES
CURRENCY RECEIVABLE
TRANSLATION TREASURY UNEARNED FROM
ADJUSTMENT STOCK COMPENSATION OFFICERS
----------- -------- ------------ ----------
<S> <C> <C> <C> <C>
Balance, December 31, 1992........................................... $ (1,721) $ (342) $ -- $ --
Sale of convertible preferred stock................................ -- -- -- --
Sale of common stock............................................... -- -- -- --
Stock issuance costs............................................... -- -- -- --
Dividends on preferred stock ($18.75 per share).................... -- -- -- --
Unearned compensation on restricted common stock................... -- -- (1,007) --
Amortization of unearned compensation.............................. -- -- 91 --
Issuance of notes receivable from officers......................... -- -- -- (230)
Sale of Canadian companies......................................... 1,754 -- -- --
Translation adjustment............................................. (33) -- -- --
Net loss........................................................... -- -- -- --
----------- -------- ------------ ----------
Balance, December 31, 1993........................................... -- (342) (916) (230)
Issuance of shares in APPL Consolidation........................... -- -- -- --
Sale of common stock............................................... -- -- -- --
Stock issuance costs............................................... -- -- -- --
Dividends on preferred stock ($450.00 per share)................... -- -- -- --
Amortization of unearned compensation.............................. -- -- 391 --
Repayments of notes receivable from officers....................... -- -- -- 88
Net loss........................................................... -- -- -- --
----------- -------- ------------ ----------
Balance, December 31, 1994........................................... -- (342) (525) (142)
Issuance of shares in APPL Consolidation........................... -- -- -- --
Reverse stock split costs.......................................... -- -- -- --
Cancellation of treasury shares.................................... -- 342 -- --
Dividends on preferred stock ($450.00 per share)................... -- -- -- --
Amortization of unearned compensation.............................. -- -- 306 --
Repayments of notes receivable from officers....................... -- -- -- 76
Net income......................................................... -- -- -- --
----------- -------- ------------ ----------
Balance, December 31, 1995........................................... -- -- (219) (66)
Cancellation of shares............................................. -- -- -- --
Dividends on preferred stock ($450.00 per share)................... -- -- -- --
Amortization of unearned compensation.............................. -- -- 140 --
Repayments of notes receivable from officers....................... -- -- -- 63
Net loss........................................................... -- -- -- --
----------- -------- ------------ ----------
Balance, September 30, 1996 (Unaudited).............................. $ -- $ -- $ (79) $ (3)
========= ======= =========== ========
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-6
<PAGE> 74

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of
American Exploration Company and its majority-owned subsidiaries (collectively
referred to as "American Exploration" or the "Company"). American Exploration is
an independent company engaged in exploration, development and production of oil
and natural gas. American Exploration's oil and gas operations are conducted in
the United States with exploration and development activities concentrated
onshore in the Gulf Coast region of Texas and Louisiana and offshore in the Gulf
of Mexico. In addition to conducting oil and gas operating activities on its own
behalf, the Company manages certain producing oil and gas properties through
various limited partnerships.

The Company's investments in associated oil and gas programs are accounted
for using the proportionate consolidation method, whereby the Company's
proportionate share of each program's assets, liabilities, revenues and expenses
is included in the appropriate accounts in the consolidated financial
statements. All significant intercompany balances and transactions have been
eliminated in consolidation. Certain amounts in prior years' consolidated
financial statements have been reclassified to conform with current
classifications.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions which affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results may differ from those
estimates.

Cash Equivalents

The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents. The effect of exchange
rate changes on cash was not significant during 1993, the last year during which
the Company conducted foreign operations.

Property, Plant and Equipment

The Company accounts for its oil and gas exploration and production
activities using the successful efforts method of accounting. Under this method,
acquisition costs for proved and unproved properties are capitalized when
incurred. Exploration costs, including geological and geophysical costs and
costs of carrying and retaining unproved properties, are charged to expense as
incurred. The costs of drilling exploratory wells are capitalized pending
determination of whether each well has resulted in the discovery of proved
reserves. If proved reserves are not discovered, such drilling costs are charged
to expense. Costs incurred to drill and equip development wells, including
unsuccessful development wells, are capitalized. Internal costs related to the
acquisition, development and exploration of oil and gas properties are expensed
as incurred. Interest is capitalized on qualifying assets, primarily unproved
and unevaluated properties.

Depletion of the cost of producing oil and gas properties is computed on
the unit-of-production method. The Company also accrues for platform abandonment
costs related to its offshore platform facilities on the unit-of-production
method. The Company anticipates total abandonment costs to be approximately $8.5
million. As of December 31, 1995, the Company had accrued $6.1 million, which is
included in accumulated depreciation, depletion and amortization ("DD&A").
Unproved properties are assessed periodically, and any impairment in value is
recognized currently as impairment expense. In 1995, the Company recorded a $1.8
million impairment of an unproved property on which no further exploration is
planned.

F-7
<PAGE> 75

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

Effective March 1995, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of". Under the provisions of the new
statement, if the net book value of an individual proved oil or gas field is
greater than its undiscounted future net cash flow from proved reserves, then an
impairment is recognized for the difference between the net book value and the
fair value. The fair value used to calculate the impairment for an individual
field is equal to the present value of its future net cash flows. In 1994,
American Exploration recorded a noncash impairment charge of $25.0 million when
the Company changed its impairment policy to one consistent with that required
by SFAS No. 121. Previously, the Company's impairment policy was to recognize an
impairment of proved oil and gas property costs if, on a company-wide basis,
those costs exceeded the undiscounted after-tax future net cash flows from
proved reserves.

Property, plant and equipment other than oil and gas properties are
depreciated by the straight-line method at rates based on the estimated useful
lives of the assets. Repairs and maintenance are charged to expense as incurred;
renewals and betterments are capitalized.

Investment Programs

The Company manages various investment programs which were formed to
acquire interests in producing oil and gas properties. The Company charges each
investment program fees for reimbursement of expenses incurred in managing the
program's operations and certain fees for services provided by technical
employees of the Company. Such fees are recorded as reductions to general and
administrative expense. (See Notes 11 and 18.)

Assets Held for Sale

In July 1996, the limited partners of the New York Life Oil and Gas
Producing Properties Programs (the "NYLOG Programs"), a series of publicly
registered limited partnerships of which a Company subsidiary is a co-general
partner, approved the liquidation of the partnerships. The Company is in the
process of selling interests in approximately 70 properties, including those
properties owned by the NYLOG Programs and certain related properties (the "1996
Sales"), and expects to complete the sales by year-end 1996. The Company's
interests in the properties that are expected to be sold in the 1996 Sales have
been classified as assets held for sale in the accompanying balance sheet as of
September 30, 1996. Although there can be no assurance as to the amount of
proceeds to be derived from such sales, the Company believes that the net
proceeds from the property dispositions will exceed the current carrying value
of the properties. Accordingly, the assets held for sale are stated at net book
value. (See Note 18.)

Assets held for sale also include certain interests in High Island Block
116 that were acquired by the Company in September 1996 and that are expected to
be sold to a third party during the fourth quarter of 1996. (See Note 3.)

Financial Instruments

The Company periodically enters into commodity price swap agreements in
order to hedge against volatility in oil and gas prices. Gains or losses on
these transactions are reported as a component of oil and gas sales in the
period during which the related production occurs. (See Note 13.)

Gas Balancing

The Company utilizes the sales method of accounting for natural gas
revenues whereby revenues are recognized based on the amount of gas sold to
purchasers. The amount of gas sold may differ from the amount to which the
Company is entitled based on its working interests in the properties. At
December 31, 1994 and

F-8
<PAGE> 76

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

1995, the Company had recorded a liability of $3.7 million and $3.6 million,
respectively, for properties having insufficient reserves from which to recover
the gas imbalance.

Foreign Currency Translation

The results of operations attributable to the Company's Canadian
operations, which were sold in mid-1993, were measured using the local currency
as the functional currency. The adjustments resulting from the translation of
the assets and liabilities and income statement accounts of the Canadian
operations were accumulated in the foreign currency translation adjustment
component of stockholders' equity. In conjunction with the sales of the
Company's Canadian operations, the Company wrote off the foreign currency
translation adjustment balance of approximately $1.8 million to loss on sales of
oil and gas properties. (See Note 4.) The U.S. dollar was the functional
currency for the Company's other foreign operations. Foreign currency
transaction gains and losses were recognized currently in other income and were
not material for 1993. The Company had no foreign operational activity during
1994 or 1995.

Income Taxes

The income tax provision (benefit) reflects income taxes currently payable
and income taxes deferred due to temporary differences between the financial
statement and tax bases of assets and liabilities. Deferred tax assets and
liabilities are determined using enacted tax rates in effect for the year in
which the temporary differences are expected to reverse. The adoption of SFAS
No. 109, "Accounting for Income Taxes", effective January 1, 1993, did not have
a material impact on the Company's financial position or results of operations.
(See Note 12.)

Net Income (Loss) Per Common Share

Net income (loss) per common share has been computed by dividing net income
or loss, after reductions for certain preferred stock dividends, by the weighted
average number of common shares and common share equivalents outstanding during
each year. Common share equivalents include the average shares issuable upon
assumed exercise of stock options and warrants which would have a dilutive
effect in the respective periods. Any assumed exercises of stock options or
warrants were antidilutive for all three years presented. In addition, any
assumed conversion of convertible preferred stock was antidilutive for 1994 and
1995. The weighted average shares used in the primary earnings per share
calculations were 6,961,600, 8,060,800 and 11,811,500 in the years ended
December 31, 1993, 1994 and 1995, respectively, and were 11,812,000 and
11,811,000 in the nine months ended September 30, 1995 and 1996, respectively.
Weighted average shares for prior periods have been retroactively restated to
reflect the one-for-ten reverse split of the Company's common stock. (See Note
2.)

Interim Financial Statements

The consolidated financial statements for the nine months ended September
30, 1995 and 1996 have been prepared, without audit, pursuant to the rules and
regulations of the Securities and Exchange Commission. The financial statements
reflect adjustments of a normal recurring nature which are, in the opinion of
management, necessary to present fairly such information. Results for the
interim periods are not necessarily indicative of the results which may be
achieved for an entire year.

(2) REVERSE STOCK SPLIT

In June 1995, American Exploration's stockholders approved an amendment to
the Company's Restated Certificate of Incorporation which effected a one-for-ten
reverse split of its common stock (the "Reverse Stock Split") and also reduced
the number of authorized shares of common stock from 200,000,000 to

F-9
<PAGE> 77

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

50,000,000. As a result of the Reverse Stock Split, the number of outstanding
shares of common stock was reduced to approximately 11.8 million shares
outstanding from approximately 118.1 million shares outstanding immediately
prior to the Reverse Stock Split. In addition, approximately $5.3 million was
reclassified on the consolidated balance sheet from common stock to additional
paid-in capital. The remaining shares of treasury stock held by American
Exploration prior to the Reverse Stock Split were cancelled. The stockholders'
equity accounts on the accompanying balance sheets have been restated to give
retroactive recognition to the Reverse Stock Split for all periods presented. In
addition, all references to numbers of shares of common stock and per share
amounts have been restated throughout this report.

(3) ACQUISITIONS

APPL CONSOLIDATION

During the period 1983-1990, American Exploration obtained long-term
funding for many of its oil and gas property acquisitions through a series of
investment programs formed primarily with institutional investors ("APPL
Programs"). As of December 31, 1993, institutional investors had committed
$507.7 million to these programs, while the Company had committed $54.7 million.
The APPL Programs consisted primarily of limited partnerships ("APPL
Partnerships") in which the Company acted as general partner and the
institutions invested as limited partners. To meet the needs of tax-exempt
investors, the Company also formed programs structured as secured debt
financings ("APPL Debt Programs") and programs which invested in net profits
interests.

During 1994 and 1995, the Company purchased limited partners' interests in
the APPL Partnerships and net profits interests and debt interests in the APPL
Debt Programs (the "APPL Consolidation"). The consideration paid for the
acquisition of the APPL interests in 1994 was a combination of $31.1 million in
cash and 4.3 million shares of the Company's common stock. In connection with
the transaction, $13.6 million in nonrecourse debt was eliminated, resulting in
an extraordinary gain totaling $5.4 million. In 1995, the Company repurchased
the remaining investors' interests in the APPL Programs for a combination of
$2.3 million in cash and the issuance of 346,000 shares of the Company's common
stock, thereby eliminating the remaining $6.6 million of nonrecourse debt
outstanding at year-end 1994. The elimination of the APPL debt in 1995 resulted
in an extraordinary gain of $2.5 million. No income tax expense has been
recognized on the extraordinary gains.

In May 1995, New York Life Insurance Company ("New York Life") transferred
certain of its limited partner's interests not acquired in the APPL
Consolidation to ANCON Partnership Ltd. ("ANCON"). The Company acquired a 20%
interest in these properties for approximately $6.7 million in cash. (See Note
11.)

The Company financed the cash portion of the APPL Consolidation primarily
through a $40.0 million nonrecourse secured credit facility ("bridge facility")
extended by New York Life. In February 1995, the Company refinanced the amount
outstanding on the bridge facility using excess borrowing capacity under its
bank credit facility. (See Note 7.)

1996 ACQUISITIONS

On March 15, 1996, the Company and Dominion Reserves, Inc. acquired
interests in five offshore blocks in the Gulf of Mexico from a private company
for a purchase price of approximately $56.0 million (the "March 1996
Acquisition"). American Exploration's 25% share of the acquisition was funded
through $14.0 million in borrowings under the Company's bank credit facility.

On September 27, 1996, the Company acquired interests in two blocks in the
Gulf of Mexico, High Island Block 116 and East Cameron Block 328, for a purchase
price of approximately $39 million, net of

F-10
<PAGE> 78

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

interests being sold to a third party (the "September 1996 Acquisition"). The
September 1996 Acquisition was funded through borrowings under the Company's
revolving bank credit agreement.

(4) DIVESTITURES

The Company received cash proceeds, net of post-closing adjustments, of
$35.7 million, $2.6 million and $63.5 million from the sales of oil and gas
properties in 1993, 1994 and 1995, respectively, resulting in a loss of $6.9
million in 1993 and gains of $1.1 million in 1994 and $10.2 million in 1995. The
1993 sales related primarily to the Company's divestiture of its Canadian
operations and the sale of a partial interest in the Henderson Canyon Field.
Property sales in 1994 related to the divestiture of low-value properties and
sales in 1995 related primarily to the sale of the Sawyer Field.

In March 1993, American Exploration sold approximately 40% of its interest
in the Henderson Canyon Field to several of the Company's investment programs
for proceeds of approximately $8.7 million. In June and July 1993, the Company
sold its Canadian foothill properties (while retaining a 4% overriding royalty
interest in these properties) and also sold its 90% equity interest in Canadian
Conquest Exploration, Inc. and its wholly owned subsidiary, Conquest Ventures
Canada, Inc., for aggregate proceeds of $26.1 million. The Company recognized
losses totaling $4.0 million on the sales of the Canadian assets. In conjunction
with the sales of the Canadian subsidiaries, the Company also recognized a $1.8
million loss related to the elimination of the foreign currency translation
adjustment balance which was previously recorded as a component of stockholders'
equity. The remaining $1.1 million loss on sales of oil and gas properties for
1993 related to the sale of minor properties sold at auction in July 1993.

In July 1995, the Company sold its interest in the Sawyer Field to Louis
Dreyfus Natural Gas Corp. for a purchase price of $64.0 million. As part of the
sale, the Company also sold its interest in the field that was acquired through
the APPL Consolidation in early 1995. (See Note 3.) American Exploration's share
of the net proceeds from the sale was applied to eliminate $62.5 million of the
Company's outstanding bank debt. The Company recorded a gain on the sale of the
Sawyer Field of approximately $10.6 million in 1995. Sales of various other
fields in 1995 resulted in a net loss of approximately $400,000.

(5) PRO FORMA INFORMATION (UNAUDITED)

The following pro forma summary of consolidated results of operations for
the years ended December 31, 1994 and 1995 gives effect to the APPL
Consolidation and the sale of the Sawyer Field as if these transactions had
occurred as of January 1, 1994. The pro forma data also reflects the impact of
the 1995 sales of interests in several other fields for proceeds of
approximately $2.5 million. The pro forma data does not reflect the nonrecurring
gain of approximately $10.6 million on the sale of the Sawyer Field.

F-11
<PAGE> 79

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

As a result of the APPL Consolidation in 1994 and 1995, American
Exploration acquired significant additional interests in the Sawyer Field,
increasing its working interest ownership from approximately 12.5% at the
beginning of 1994 to approximately 65% at the date of the sale. Therefore, the
pro forma data reflects the sale of the 65% interest in the Sawyer Field, after
giving effect to the APPL Consolidation.

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
--------------------
1994 1995
-------- --------
(IN THOUSANDS EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Pro forma revenues.............................................. $ 63,234 $ 62,090
Pro forma loss before extraordinary item........................ (53,480) (8,672)
Pro forma net loss to common stock.............................. (44,688) (10,472)
Pro forma net loss per common share:
Primary and fully diluted:
Loss before extraordinary item............................. $ (4.71) $ (0.89)
Net loss................................................... (3.81) (0.89)
Weighted average shares outstanding:
Primary and fully diluted..................................... 11,726 11,811
</TABLE>

The following pro forma summary of consolidated results of operations for
the nine months ended September 30, 1995 and 1996 gives effect to: (i) the
completion of the APPL Consolidation in the first half of 1995 for a purchase
price of approximately $9.0 million; (ii) the sale of the Sawyer Field in July
1995; (iii) the 1995 sales of interests in several other fields for
approximately $2.5 million; (iv) the March 1996 Acquisition; (v) the September
1996 Acquisition; and (vi) the 1996 Sales, as if these transactions had occurred
as of January 1, 1995.

The pro forma results for the nine-month period of 1996 include only two
months of results from the High Island 116 well acquired in the September 1996
Acquisition, and the pro forma results for the nine-month period of 1995 do not
include any results from that well because the well did not produce during the
applicable period. The well commenced production in August 1996 at a net
production rate of approximately 300 Bbls of oil per day and approximately
17,100 Mcf of natural gas per day. Similarly, the 1995 pro forma results include
only seven months of results from the East Cameron 328 well, also purchased in
the September 1996 Acquisition, which commenced production in March 1995. In
addition, the 1995 pro forma results have been adjusted to eliminate the
nonrecurring gain on the sale of the Sawyer Field of approximately $10 million.

<TABLE>
<CAPTION>
FOR THE NINE
MONTHS ENDED
SEPTEMBER 30,
------------------
1995 1996
------- -------
(IN THOUSANDS
EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Pro forma revenues................................................ $48,950 $53,840
Pro forma loss before extraordinary item.......................... (5,303) (9,027)
Pro forma net loss to common stock................................ (2,847) (9,027)
Pro forma net loss per common share:
Primary and fully diluted:
Loss before extraordinary item............................... $ (0.45) $ (0.76)
Net loss..................................................... (0.24) (0.76)
Weighted average shares outstanding:
Primary and fully diluted....................................... 11,812 11,811
</TABLE>

F-12
<PAGE> 80

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

The pro forma amounts do not purport to be indicative of the results of
operations of American Exploration that may be reported in the future or that
would have been reported had these transactions occurred as of the dates
indicated above.

(6) NYLOG PROGRAMS

From 1985 until early 1992, subsidiaries of the Company and New York Life
formed the NYLOG Programs. The NYLOG Programs invest in the acquisition and
further development of producing oil and gas properties acquired by the Company.
A total of $229.1 million has been invested by the limited partners in these
programs since inception. (See Note 11.)

New York Life and the Company, in their capacity as co-general partners,
each pay 5% of property acquisition costs of the NYLOG Programs, and each
receives 7.5% of net revenues until payout. Payout occurs when the limited
partners receive distributions equal to their initial investment. After payout,
the Company's and New York Life's interests in capital costs and net revenues
each increase to 12.5%. As of December 31, 1995, two of the NYLOG Programs had
reached payout. For the other NYLOG Programs, it is difficult to predict when or
if payout will occur due to the uncertainty of future energy prices, oil and gas
production, and operating and administrative costs.

Reference is made to Note 18 for a discussion of certain litigation against
the co-general partners and the proposed liquidation of the NYLOG Programs.

(7) DEBT

The following table details the components of the Company's debt (in
thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
------------------- SEPTEMBER 30,
1994 1995 1996
-------- ------- ------------
<S> <C> <C> <C>
Bank credit agreement........................ $ 28,000 $ 5,000 $ 70,000
11% senior subordinated notes................ 35,000 35,000 35,000
Note payable to related party................ 31,128 -- --
APPL Debt promissory notes................... 6,582 -- --
-------- ------- ------------
Total long-term debt............... $100,710 $40,000 $105,000
======== ======= =========
</TABLE>

BANK DEBT

In December 1994, the Company entered into a new long-term revolving bank
credit agreement which replaced the bank credit agreement previously in effect.
The borrowing base, or amount available, under the new bank credit facility is
currently $40.0 million. The reduction of the borrowing base from $65.0 million
at year-end 1994 reflects the decrease in the value of the Company's oil and gas
properties due to the sale of the Sawyer Field. Outstanding borrowings of $5.0
million under the facility at December 31, 1995 were classified as long-term
debt. The Company also had $1.2 million in letters of credit outstanding at
December 31, 1995 which are collateralized by the Company's borrowing base. The
borrowing base under this facility is scheduled to be redetermined semiannually
every March and September. Management expects that the borrowing base will be
increased to give effect to the acquisition of certain interests in the Gulf of
Mexico in March 1996. (See Note 18.)

As of September 30, 1996, the borrowing base under the bank credit
agreement was $90 million, reflecting the increase in the aggregate value of the
Company's oil and gas properties due to the March 1996 Acquisition and the
September 1996 Acquisition. The Company has filed a registration statement with
the Securities and Exchange Commission regarding the proposed sale by the
Company of 3,000,000 shares of the

F-13
<PAGE> 81

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

Company's common stock for estimated net proceeds of approximately $33.8
million. If the common stock offering is completed and the net proceeds are
applied to reduce bank debt, the Company anticipates that the amount outstanding
under the bank credit agreement will be approximately $21.8 million and the
borrowing base will be approximately $75 million.

The borrowings under this facility during 1995 were used to refinance the
$31.1 million balance outstanding under the bridge facility and to fund capital
projects. In July 1995, American Exploration repaid $62.5 million of outstanding
bank debt using proceeds from the sale of the Company's interest in the Sawyer
Field.

Borrowings under this facility are secured by substantially all of the
assets of the Company. At the option of the Company, borrowings bear interest at
(i) LIBOR plus 1.50% or 1.75% or (ii) the higher of (a) the prime rate plus
0.50% or 0.75% or (b) the federal funds rate plus 1.00% or 1.25%. If the total
amounts outstanding are less than or equal to 60% of the borrowing base, the
lower margins are added to the respective interest rates and vice versa. The
weighted average interest on the Company's bank debt outstanding at December 31,
1995 was 8.2%. During 1995, the Company paid, on a quarterly basis, a 0.50%
annual commitment fee on the difference between the aggregate commitment of
$90.0 million and the daily average amount outstanding under this facility,
including letters of credit. In January 1996, the Company renegotiated the
annual commitment fee to be 0.50% of the difference between the availability
limit of $40.0 million and the average amount outstanding, including letters of
credit. Principal on the remaining long-term portion of the facility is
scheduled to be repaid over ten quarterly installments commencing September 30,
1997. Interest is payable quarterly or upon maturity of the borrowing, if
shorter, in the case of Eurodollar loans and monthly in the case of prime rate
or federal funds rate loans.

Under the terms of an amendment to the bank credit agreement dated October
15, 1996, principal payments under the facility were rescheduled to be repaid in
ten quarterly installments commencing September 30, 1999.

11% SENIOR SUBORDINATED NOTES

In December 1991, the Company privately placed $35.0 million in senior
subordinated notes and immediately exercisable detachable warrants with three
institutional investors. The notes bear interest at 11% payable semiannually
every June and December. The Company is required to begin repaying principal
with annual installments of $5.6 million in December 1997. The final principal
payment of $12.6 million is payable in December 2001. The warrants grant the
holders the right to purchase approximately 1.2 million shares, as adjusted for
issuances of stock and warrants subsequent to 1991, of the Company's common
stock at an exercise price of $22.37 per share, subject to adjustment. In
addition, each holder of the warrants has the option to tender the notes in lieu
of cash as consideration for the exercise price.

In September 1996, holders of the senior subordinated notes agreed to an
extension of the principal payment dates of the notes, which were scheduled to
begin in December 1997, in exchange for a reduction in the exercise price, from
$22.95 per share to $15.53 per share, of the warrants. As a result of this
extension, annual principal payments of approximately $11.7 million on the notes
will begin in December 2002.

NOTE PAYABLE TO RELATED PARTY

In April 1994, New York Life extended to the Company a $40.0 million bridge
facility to provide bridge financing for the APPL Consolidation. In February
1995, the Company used excess borrowing capacity under the bank credit facility
to refinance the $31.1 million balance outstanding under the bridge facility.

F-14
<PAGE> 82

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

APPL DEBT PROMISSORY NOTES

During 1987 and 1988, wholly owned subsidiaries of the Company financed 90%
of the cost of certain property acquisitions by selling promissory notes and
production payments to the investors in the APPL Debt Programs. The Company
eliminated $13.6 million of the APPL debt in 1994 and $6.6 million of the APPL
debt in 1995. The elimination of the APPL debt through the APPL Consolidation
resulted in an extraordinary gain on extinguishment of debt of $5.4 million in
1994 and $2.5 million in 1995. No income tax expense has been recognized on the
extraordinary gains. (See Note 3.)

FEES RELATED TO DEBT INSTRUMENTS

The Company incurs fees related to existing and new credit facilities which
are reported as other expense. During 1993, 1994 and 1995, these fees totaled
$739,000, $2.3 million and $951,000, respectively. Fees paid in 1994 included
$2.1 million incurred in connection with the new bank credit agreement and the
bridge facility.

DEBT COVENANTS

The bank credit agreement and the 11% senior subordinated notes require the
Company to comply with certain covenants including, but not limited to,
restrictions on indebtedness, investments, payment of dividends and lease
commitments. Cash dividends are prohibited on the Company's common stock, and
preferred dividends are limited to the lesser of 10% of the preferred stock
offering proceeds or $7.5 million in any one year. These agreements also include
net worth covenants which were amended effective July 1994 in conjunction with
the issuance of American Exploration common stock related to the APPL
Consolidation. At December 31, 1995, the Company's calculated net worth
requirement was $64.6 million and the Company's stockholders' equity was $94.5
million. In addition, these agreements contain cross-default provisions.

ANNUAL MATURITIES

Based on the amounts outstanding at December 31, 1995, the aggregate
maturities of debt for the next five years are as follows: 1996 -- $-0-;
1997 -- $6.6 million; 1998 -- $7.6 million; 1999 -- $7.6 million and
2000 -- $5.6 million.

(8) PREFERRED STOCK

The Company has authorized 100,000 shares of preferred stock, par value
$1.00 per share. The Board of Directors has authority to divide such preferred
stock into one or more series and has authority to fix and determine the
relative rights and preferences of each such series. At December 31, 1995,
American Exploration had 4,000 shares of convertible preferred stock outstanding
and an additional 85,000 shares of preferred stock reserved under the Company's
Stockholder Rights Plan.

CONVERTIBLE PREFERRED STOCK

In December 1993, the Company privately placed 800,000 depositary shares,
each representing a 1/200 interest in a share of $450 Cumulative Convertible
Preferred Stock, Series C (the "Convertible Preferred Stock"). The Convertible
Preferred Stock has a stated value of $5,000 per share, with dividends payable
quarterly at the annual rate of $450 per share. The Convertible Preferred Stock
is convertible at any time at the option of the holders into shares of the
Company's common stock at a conversion price of $15.00 per share, subject to
adjustment in certain circumstances. Beginning December 31, 1997, the
Convertible Preferred Stock will be redeemable at the option of the Company, in
whole or in part, at any time. The initial redemption price is $5,270 per share,
declining ratably on December 31 of each year to a redemption price of $5,000
per share on and after December 31, 2003, plus accrued and unpaid dividends.

F-15
<PAGE> 83

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

The Convertible Preferred Stock has a special conversion right that becomes
effective upon the occurrence of certain types of significant transactions
affecting ownership or control of the Company. If the special conversion right
becomes effective, the then-prevailing conversion price would be reduced to the
market value of the common stock, not to be reduced below a minimum conversion
price of $11.25 per share of common stock.

STOCKHOLDER RIGHTS PLAN

In September 1993, the Board of Directors of the Company declared a
distribution of one right ("Right") for each outstanding share of common stock
to stockholders of record at the close of business on October 8, 1993 and for
each share of common stock issued by the Company thereafter and prior to the
"Distribution Date", as defined. Each Right entitles the registered holder to
purchase one one-thousandth of a share (a "Unit") of Series B Preferred Stock at
a price of $7.50 per Unit, subject to adjustment.

The Rights are exercisable only upon the occurrence of certain triggering
events, including the acquisition by a person or group of 15% or more of the
Company's outstanding common stock, other than those persons that acquired
common stock through the APPL Consolidation. If a triggering event occurs,
holders of each Right would be entitled to receive, upon exercise, the Units of
Series B Preferred Stock (or stock of the acquiring entity, as the case may be)
having a value equal to two times the exercise price of the Right. Such Rights
do not extend to any holder whose action triggered the Right.

The Rights may be redeemed in whole by American Exploration at $0.10 per
Right any time until the tenth business day following public announcement that a
person or group, other than those persons that acquired common stock through the
APPL Consolidation, has acquired, obtained the right to acquire or otherwise
obtained beneficial ownership of 15% or more of the Company's outstanding common
stock.

(9) COMMON STOCK

The Company has authorized 50,000,000 shares of common stock, of which
11,812,483 shares were issued and outstanding at December 31, 1995. A schedule
of the changes in the Company's common stock is provided below:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1993 1994 1995
--------- ---------- ----------
<S> <C> <C> <C>
Outstanding shares at beginning of year........... 6,941,723 7,051,350 11,468,313
Issuance of shares in APPL Consolidation (see Note
3).............................................. -- 4,266,963 346,094
Issuance of shares in private offering............ -- 150,000 --
Issuance of shares to key officers................ 109,588 -- --
Other issuances (retirements)..................... 39 -- (1,924)
--------- ---------- ----------
Outstanding shares at end of year............ 7,051,350 11,468,313 11,812,483
======== ========= =========
</TABLE>

At the Company's annual meeting held in June 1995, American Exploration
obtained stockholder approval to effect the Reverse Stock Split and to decrease
the number of authorized shares of common stock from 200,000,000 shares to
50,000,000 shares. (See Note 2.)

At December 31, 1995, the Company had outstanding two series of warrants to
purchase common stock. The first series of warrants, issued in conjunction with
the private placement of 11% senior subordinated notes in 1991, expires in 2001
(the "2001 Warrants"). At year-end 1995, the 2001 Warrants were exercisable at a
price of $22.37 per share and are callable by the Company beginning in December
1996, but only in the event

F-16
<PAGE> 84

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

that the Company's common stock has traded at a specified price above the
exercise price for a specified period.

The second series of warrants, which expire in 1999, was issued to an
institutional investor in conjunction with the 1992 recapitalization of a
Canadian subsidiary (the "1999 Warrants"). At year-end 1995, the 1999 Warrants
were exercisable at a price of $22.95 per share and are callable by the Company
at the current exercise price per warrant, but only in the event that the
Company's common stock has traded at a specified price above the current
exercise price for a specified period.

Both the 2001 Warrants and the 1999 Warrants contain provisions which would
adjust the exercise price and number of warrants under certain circumstances,
most of which have a dilutive effect on equity.

Shares of common stock reserved for future issuance as of December 31, 1995
were as follows:

<TABLE>
<S> <C>
Exercise of stock options........................................ 1,384,443
Exercise of 2001 Warrants........................................ 1,166,740
Exercise of 1999 Warrants........................................ 313,726
Conversion of Convertible Preferred Stock........................ 1,333,333
Special conversion rights of Convertible Preferred Stock......... 444,444
---------
Total shares reserved.................................. 4,642,686
========
</TABLE>

(10) EMPLOYEE BENEFIT PLANS

STOCK COMPENSATION PLANS

The American Exploration Company Stock Compensation Plan established in
1983 (the "1983 Plan") provides for the issuance of up to 500,000 shares of the
Company's common stock. The 1983 Plan also authorizes the issuance of stock
appreciation rights in conjunction with stock options and the granting of
restricted common stock and performance shares. In 1993, the executive officers
of the Company purchased 79,725 shares of restricted common stock for $.50 per
share. The difference between the aggregate fair market value of the restricted
shares purchased and the purchase price was considered unearned compensation at
the time of grant, and compensation is being earned ratably over the vesting
period at 33 1/3% per year commencing with the first anniversary of grant. In
1995 and 1994, $306,000 and $391,000 of restricted stock compensation expense
was recognized. During the three-year reporting period, no other restricted
common stock was issued nor were any stock appreciation rights or performance
shares granted under the 1983 Plan.

In November 1994, the Board of Directors adopted the 1994 American
Exploration Company Stock Compensation Plan (the "1994 Plan"), which was
approved by American Exploration's stockholders in June 1995. Under the 1994
Plan, 900,000 shares of the Company's common stock are available for the
granting of stock options, restricted common stock and performance shares. In
addition, performance units may be awarded and stock appreciation rights may be
issued in conjunction with the stock options.

The exercise price, term and other conditions applicable to each option
granted under the 1983 Plan and the 1994 Plan are determined at the time of the
grant of each option and may vary with each option granted. No option may be
granted at a price less than the stock's fair market value on the date of grant.
The purchase price of the shares as to which an option is exercised is payable
in cash, the Company's common stock or a combination of cash and stock.

In conjunction with the acquisition of Hershey Oil Corporation ("Hershey")
in 1990, the Company assumed the obligation for the stock options outstanding
under the Hershey plans at the acquisition date. At December 31, 1995, there
were 37,295 options outstanding under the amended and restated Hershey plans.

F-17
<PAGE> 85

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

Detailed information on stock option transactions is provided below:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1993 1994 1995
------------ ------------ ------------
<S> <C> <C> <C>
Options outstanding at beginning of year.... 562,458 374,258 289,653
Options granted............................. 1,020 -- 593,321
Options terminated.......................... (189,200) (84,605) (99,108)
Options exercised........................... (20) -- (20)
------------ ------------ ------------
Options outstanding at end of year.......... 374,258 289,653 783,846
=========== =========== ===========
Options exercisable at end of year.......... 271,190 242,466 361,633
=========== =========== ===========
Option price range:
Options granted........................... $12.50-14.38 $ -- $ 8.75-15.00
Options terminated........................ 18.13-50.00 18.13-50.00 12.50-47.50
Options exercised......................... 12.50-14.38 -- 8.75
Options outstanding at end of year........ 13.13-50.00 13.13-47.50 11.87-40.00
</TABLE>

PHANTOM STOCK PLAN

In September 1993, the Board of Directors of the Company adopted the
Phantom Stock Plan. The purpose of the Phantom Stock Plan is to provide a
further means of motivating and retaining key employees of the Company by
providing rewards for past performance and incentives for future service. These
rewards had previously included restricted units and option units; however, in
1995, all participants exercised their right to convert outstanding option units
to stock options under the 1994 Plan.

In 1993, the executive officers of the Company purchased 29,863 shares of
common stock, purchased 79,725 shares of restricted common stock under the 1983
Plan and were awarded 159,450 option units under the Phantom Stock Plan. The
remaining key employees were granted 650 restricted units and 1,300 option units
in 1995, 5,650 restricted units and 11,300 option units in 1994, and 33,791
restricted units and 67,581 option units in 1993. In each case, the price for
the option units equaled the fair market value of the Company's common stock on
the date of the awards. The grant price for the restricted units to the
remaining key employees was below market value.

The restricted units awarded vest at 33 1/3% per year commencing with the
first anniversary of grant. Upon vesting, a participant receives a cash payment
for the difference between the grant price for the restricted units and the
then-market value of the common stock. Such cash payments totaled $44,000 and
$24,000 for 1995 and 1994, respectively. Under the Phantom Stock Plan,
participants do not receive shares of the Company's common stock. The Company
recognizes compensation expense ratably over the vesting period of the
restricted units for the difference between the grant price and the then-market
value of the common stock. Such expense totaled $25,000, $22,000 and $59,000 in
1993, 1994 and 1995, respectively.

EMPLOYEE STOCK OWNERSHIP PLAN

The employee stock ownership plan was a noncontributory plan to acquire
shares of the Company's common stock for the benefit of all employees. At the
discretion of the Compensation Committee of the Board of Directors, there have
been no Company contributions to the plan since 1992. In September 1994, the
Board of Directors voted to terminate the plan. A favorable ruling on the plan's
termination was received from the Internal Revenue Service in November 1995, and
distributions to the plan's participants were made in February 1996.

F-18
<PAGE> 86

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(11) RELATED-PARTY TRANSACTIONS

NOTES RECEIVABLE FROM OFFICERS

At December 31, 1995, the Company held $66,000 of notes receivable from
executive officers of the Company. The Company provided loans to the executive
officers to purchase a portion of the common stock issued in September 1993 in
conjunction with the Phantom Stock Plan. The notes bear interest at 3.9% and are
payable in equal installments through October 1996.

NEW YORK LIFE

As of December 31, 1995, New York Life was the second largest stockholder
of the Company, owning approximately 9.6% of its voting stock. Since 1983, New
York Life had been a substantial investor in each of the Company's APPL
Programs, providing 35% of the amount committed by co-investors. New York Life
made no investments in the APPL Programs during the past three years. In
conjunction with the APPL Consolidation, New York Life sold certain of its APPL
Program interests to the Company and transferred its remaining interests to
ANCON. (See Note 3.)

During the period 1985-1992, the Company and a subsidiary of New York Life,
as co-general partners, formed the NYLOG Programs, which were sold to the public
by New York Life agents and independent broker-dealers. New York Life
contributed $1.3 million, $74,000 and $29,000 for development and acquisition
activity by the NYLOG Programs for the years ended December 31, 1993, 1994 and
1995, respectively. (See Notes 6 and 18.)

In December 1993, American Exploration and a subsidiary of New York Life
established ANCON, a new partnership formed to consolidate New York Life's other
oil and gas holdings. New York Life contributed net assets to the partnership
totaling $56.7 million in 1995, consisting primarily of its remaining APPL
Program interests, and $9.6 million in 1993. American Exploration acquired a 20%
interest in these net assets for cash consideration of $1.5 million in 1993 and
$6.7 million in 1995. No properties were contributed to the partnership in 1994.
Capital contributions by New York Life to ANCON for development activity totaled
$813,000 in 1994. No capital contributions were made for development activity in
1995.

In April 1994, New York Life extended to the Company a $40.0 million bridge
facility. (See Note 7.) American Exploration paid interest, commitment and
financing fees on this facility totaling $1.6 million in 1994. At December 31,
1994, the Company had $31.1 million outstanding under this facility. In February
1995, the Company refinanced this amount using excess borrowing capacity under
its bank credit facility.

INVESTMENT PROGRAMS

The Company is the operator of certain properties owned by the NYLOG
Programs, ANCON and joint ventures and, accordingly, charges technical fees to
these entities and third party joint interest owners. The Company is also
reimbursed for costs incurred in managing the operations of the NYLOG Programs
and ANCON. Administrative and technical fees charged by the Company to the
investment programs and ANCON totaled $8.2 million, $7.6 million and $3.9
million for 1993, 1994 and 1995, respectively. These fees also include amounts
related to the APPL Programs which were consolidated into American Exploration's
operations during 1994 and early 1995.

OTHER TRANSACTIONS

Legal fees incurred for services by a law firm in which a partner was a
director of the Company until June 1995 totaled $243,000, $377,000 and $285,000
in 1993, 1994 and 1995, respectively.

F-19
<PAGE> 87

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(12) INCOME TAXES

Effective January 1, 1993, the Company adopted SFAS No. 109. The prior
year's financial statements were not adjusted to reflect the new accounting
method, and the cumulative effect related to the adoption of SFAS No. 109 had no
material effect on the Company's financial position or results of operations.
SFAS No. 109 requires the use of an asset and liability approach under which
deferred tax assets and liabilities are recognized for the estimated future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases.

The Company reported income before income taxes and extraordinary items
totaling $1.4 million in 1995, which related entirely to domestic operations.
The Company's income tax provision (benefit) for the years ended December 31,
1993, 1994 and 1995 is detailed below (in thousands):

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Current:
Federal.................................... $ 150 $ -- $ 58
State...................................... 476 39 (18)
-------- -------- --------
626 39 40
-------- -------- --------
Deferred:
Federal.................................... -- -- --
State...................................... (121) (494) (161)
-------- -------- --------
(121) (494) (161)
-------- -------- --------
Total.............................. $ 505 $ (455) $ (121)
======== ======== ========
</TABLE>

The difference between the provision (benefit) for income taxes and the
amount which would be determined by applying the statutory federal income tax
rate to income (loss) before income taxes and extraordinary items for the years
ended December 31, 1993, 1994 and 1995 is analyzed below (in thousands):

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Income (loss) before income taxes
and extraordinary item..................... $(18,674) $(60,690) $ 1,356
======== ======== ========
Income tax provision (benefit)
at the statutory rate...................... $ (6,536) $(21,242) $ 475
Change in valuation allowance................ (1,133) 22,203 (75)
Federal alternative minimum tax.............. 150 -- 58
State income tax............................. 476 39 (18)
Other........................................ 7,548 (1,455) (561)
-------- -------- --------
Income tax provision (benefit)..... $ 505 $ (455) $ (121)
======== ======== ========
</TABLE>

F-20
<PAGE> 88

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

The Company's deferred income tax liability at December 31, 1994 and 1995
is comprised of the tax benefit (cost) associated with the following items (in
thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1995
-------- --------
<S> <C> <C>
Deferred tax asset:
Net operating loss carryforwards.................... $ 95,732 $ 95,869
State income tax.................................... 3,203 2,790
Investment tax credit carryforwards................. 1,873 1,873
Minimum tax carryforwards........................... 479 559
-------- --------
Gross deferred tax asset......................... 101,287 101,091
Valuation allowance................................... (93,221) (93,146)
-------- --------
8,066 7,945
-------- --------
Deferred tax liability:
Acquisition, exploration and development costs...... (8,066) (7,945)
State income tax.................................... (336) (175)
-------- --------
Gross deferred tax liability..................... (8,402) (8,120)
-------- --------
Net deferred tax liability............................ $ (336) $ (175)
======== ========
</TABLE>

As of December 31, 1995, the Company had cumulative net operating loss
carryforwards ("NOL's") for federal income tax purposes of approximately $274.0
million. Unless utilized, approximately 42% of this amount will expire in the
next five years. Included in the total NOL's are approximately $71.5 million
which arose through an acquisition completed in 1987, and $143.7 million which
arose through the acquisition of Conquest Exploration Company in 1991. These
acquired NOL's may be used to offset the respective subsidiaries' taxable income
subject to individual annual and cumulative limits. In addition to the
individual limitations, changes in the Company's ownership have resulted in an
overall limitation on the amount of benefit to be realized from the NOL's in the
amount of approximately $13.7 million annually. Any unused portion of the
benefit is carried forward. For 1995, the cumulative limit for utilization of
available NOL's is $76.3 million. The Company's $2.8 million state tax deferred
asset is primarily the result of separate company NOL's in individual states.
The Company also has investment tax credit carryforwards of approximately $1.9
million, which expire in the amount of approximately $11,000 annually through
1998 and will be fully expired by 2001. The Company has an alternative minimum
tax credit carryforward of approximately $559,000 which does not expire and is
available to offset regular income taxes in future years, but only to the extent
that regular income taxes exceed the alternative minimum tax in such years.

The deferred tax asset valuation allowance of $93.1 million reflects the
amounts for which utilization of the asset is not assured due to the expiration
of NOL's and the effects of future drilling costs.

F-21
<PAGE> 89

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(13) FINANCIAL INSTRUMENTS

DERIVATIVES

<TABLE>
<CAPTION>
AVERAGE MARKET PRICE
PRODUCT CONTRACT PERIOD DAILY PRODUCTION FIXED PRICE REFERENCE
- -------- ------------------------------ ---------------- ----------- ---------------------
<C> <C> <S> <C> <C> <C>
Gas January 1996 - April 1996 10,000 MMbtu $ 1.84 Houston Ship Channel
Gas January 1996 - April 1996 5,000 MMbtu 1.88 Henry Hub
Gas January 1996 - May 1996 20,000 MMbtu 1.85 Houston Ship Channel
Gas January 1996 - May 1996 10,000 MMbtu 1.88 Henry Hub
Oil January 1996 - June 1996 2,000 barrels $ 17.50 NYMEX WTI
Oil January 1996 - December 1996 1,000 barrels 17.00 NYMEX WTI
</TABLE>

With regard to the production hedged under the commodity price swap
agreements, if the market price is above the fixed price, the Company will pay
to the counterparty the difference between the fixed price and the market price;
and if the market price is below the fixed price, the Company will receive that
difference from the counterparty. The Company is exposed to credit loss in the
event of nonperformance by the other party to the swap agreements. However, the
Company anticipates that the counterparty will be able to fully satisfy its
obligation under the agreements.

During January 1996, the Company eliminated the effect of certain of its
Henry Hub gas price swap agreements by entering into offsetting positions
covering 10,000 MMbtu per day for the period from February 1996 to May 1996.

Subsequent to December 31, 1995, the Company entered into several
additional commodity price swap agreements:

<TABLE>
<CAPTION>
AVERAGE MARKET PRICE
PRODUCT CONTRACT PERIOD DAILY PRODUCTION FIXED PRICE REFERENCE
- -------- ------------------------------ ---------------- ----------- ---------------------
<C> <C> <S> <C> <C> <C>
Gas June 1996 - May 1997 20,000 MMbtu $ 1.86 Houston Ship Channel
Gas June 1996 - May 1997 2,000 MMbtu 2.13 Henry Hub
Oil April 1996 - March 1997 400 barrels $ 18.22 NYMEX WTI
Oil July 1996 - December 1996 2,000 barrels 17.80 NYMEX WTI
</TABLE>

F-22
<PAGE> 90

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table presents the carrying values and estimated fair values
of the Company's financial instruments at December 31, 1995 (in thousands):

<TABLE>
<CAPTION>
CARRYING FAIR
VALUE VALUE
-------- --------
<S> <C> <C>
Long-term debt (a)...................................... $(40,000) $(40,000)
Commodity price swap agreements (b)..................... (700) (2,600)
</TABLE>

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

(a) Fair value equals carrying value for the Company's long-term debt.

(b) The carrying value represents a liability recorded in December 1995 to
recognize the loss of correlation between actual cash prices and the prices
under the swap agreements at the Henry Hub market reference price. The fair
value of the swap agreements represents the estimated amount the Company
would pay to terminate all of the agreements at December 31, 1995, based on
the closing prices for NYMEX futures contracts on the last trading date in
December. Management believes that the Company's risk of loss on the price
swap agreements due to inflated market reference prices in 1996 will be
mitigated by the receipt of actual cash prices in excess of the fixed price
under the swap agreements.

The carrying amounts of cash and cash equivalents, trade receivables and
trade payables approximate fair value because of the short maturity of these
instruments.

(14) COMMITMENTS AND CONTINGENCIES

OPERATING LEASES

The Company has operating leases, primarily for office space, which expire
over the next six years. These operating leases frequently include renewal
options at the then-fair rental value and require that the Company pay a pro
rata share of executory costs (including taxes, maintenance and utility
expenses) incurred by the landlord. Future minimum payments under all
noncancelable operating lease obligations, including an estimated pro rata share
of operating expenses, as of December 31, 1995 are as follows (in thousands):

<TABLE>
<S> <C>
1996............................................................... $ 2,396
1997............................................................... 2,371
1998............................................................... 2,740
1999............................................................... 2,737
2000............................................................... 2,737
Thereafter......................................................... 1,762
-------
Total minimum lease payments............................. $14,743
=======
</TABLE>

The Company had no minimum rentals under noncancelable subleases as of
December 31, 1995. Rent expense totaled $4.6 million, $3.9 million and $2.7
million in 1993, 1994 and 1995, respectively, which includes the Company's share
of executory costs associated with its office leases. Sublease rentals received
during the past three years were not material.

PARTNERSHIP COMMITMENTS

The Company and certain of its subsidiaries act as general partner of a
number of limited partnerships. In such capacity, the Company and such
subsidiaries are generally liable for the obligations of the partnerships to the
extent that partnership assets are insufficient to discharge liabilities.
Several of the investment programs formed by the Company or its subsidiaries
require certain levels of insurance to cover operating and other risks

F-23
<PAGE> 91

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

inherent in the production of oil and gas. Under the terms of these programs,
the Company would be liable for any costs or damages incurred by a program
resulting from the Company's failure to carry the required insurance. The
Company believes its insurance coverage is sufficient as required by the program
agreements.

At December 31, 1995, the Company had remaining capital commitments to the
NYLOG Programs of $59,000. Under the terms of the NYLOG Programs' partnership
agreements, the Company is also obligated to repurchase certain units of limited
partner interests in the NYLOG Programs. These annual repurchase commitments are
based on formulas contained in the underlying partnership agreements and totaled
approximately $250,000 as of December 31, 1995. Reference is made to Note 18 for
a discussion of the proposed liquidation of the NYLOG Programs. If the proposed
liquidation of the NYLOG Programs is approved, the Company would no longer be
obligated to repurchase the NYLOG units of limited partner interests.

In addition, the Company has a commitment to purchase a 1% interest in any
properties transferred to ANCON by New York Life.

CONCENTRATION OF RISKS

American Exploration's revenues are derived principally from
uncollateralized sales of the Company's oil and gas production to customers in
the oil and gas industry. Market prices for oil and gas may fluctuate;
accordingly, decreases in market prices could adversely affect American
Exploration's net operating revenues and cash flows from operating activities.
In addition, the concentration of credit risk in a single industry affects the
Company's overall exposure to credit risk because customers may be similarly
affected by changes in economic and other conditions. The Company has not
experienced significant credit losses on such receivables.

LEGAL PROCEEDINGS

In addition to certain legal proceedings arising in the ordinary course of
its oil and gas business, the Company is involved in the following matters.

Bowdoin Field, Phillips and Valley Counties, Montana. In February 1995,
two Company affiliates were served with a lawsuit filed by KN Gas Supply
Services, Inc. ("KNGSS") in Federal District Court in Denver, Colorado,
requesting declaratory judgment that KNGSS had the right to reduce the contract
price for gas produced from the Bowdoin Field to market levels from October 1,
1993 forward. KNGSS also requested declaratory judgment that it has a right to
relief from the contract price due to regulatory changes, which it alleges
renders the contract commercially impracticable, and that Federal Energy
Regulatory Commission Order No. 636 is a condition subsequent which excuses
performance under the contract. KNGSS alleges that it has overpaid the Company's
affiliates and seeks a refund of approximately $2.8 million for the period
through September 1995. Although the Company cannot predict the outcome of this
proceeding, American Exploration will vigorously defend its interests in this
case and does not expect the outcome of the case to have a material adverse
impact on its financial position or results of operations.

In April 1995, the Company's affiliates filed counterclaims against KNGSS
in the lawsuit described above alleging that KNGSS failed to take and pay for
certain minimum volumes of gas, failed to pay for certain volumes of gas taken,
failed to schedule nominations and recorded improper deductions for fuel and
other losses. The Company has dismissed all of its counterclaims, except for the
claim alleging the improper

F-24
<PAGE> 92

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

deductions, for a payment from KNGSS of approximately $2.2 million and KNGSS
dismissing its commercial impracticability and condition subsequent claims.
American Exploration's share of the cash settlement totaled $1.7 million and is
primarily reflected as oil and gas revenues in the accompanying 1995 statement
of operations.

Sawyer Field -- Sutton County, Texas. The Company and an affiliated
partnership are defendants in a property damage lawsuit filed in December 1994
in the 112th Judicial District Court in Sutton County, Texas styled Claire J.
Powers, et al. vs. Don R. Giller, et al. Four related personal injury suits are
also pending against the Company and the affiliated partnership. These suits are
styled as Jane Giller, et al. vs. Enron Corp., et al. in the 113th Judicial
District Court in Harris County, Texas; Jane Giller, et al. vs. Fisher Controls
International, Inc., et al. in the 200th Judicial District Court in Travis
County, Texas; and Lynn Cooper, et al. vs. Enron Corp., et al. and Donna Lynn
Pretzer vs. Enron Corp., et al., both in the United States District Court for
the Eastern District of Texas, Marshall Division. All of these lawsuits are
related to a fire in December 1994 at a cabin owned by a landowner in the Sawyer
Field. As a result of the fire, two hunters died and a third hunter suffered
serious burns.

Pursuant to an arrangement made by the previous operator of the field, the
landowner supplied the cabin with natural gas from a nearby well as to which the
Company subsequently became the operator. The Company is alleged to have been
negligent or grossly negligent in failing to properly supply gas to the cabin.
The Company has denied that it was negligent or grossly negligent and will
vigorously defend its interests.

By agreement dated February 20, 1996 and entered into the record on March
5, 1996, the Sutton County landowners and all non-injured hunters settled out of
court. All remaining parties have agreed to litigate the case in the Travis
County suit and dismiss all other suits. Since the plaintiffs have not specified
the amount of damages being sought against the Company, it is not possible to
quantify what liabilities, if any, the Company might incur.

Public Partnership Litigation. In February 1995, the Company and American
Exploration Production Company, a subsidiary of the Company ("AEPCO"), were
served with a lawsuit instituted in October 1994 styled Richard Riley and
Frances Riley v. Leroy Wolf, New York Life Insurance Company, NYLIFE Equity,
Inc., NYLIFE Realty Income Partners I, L.P., New York Life Oil and Gas Producing
Properties II-E, L.P., Linclay Investment Properties, Inc., American Exploration
Production Company, John Does (1-10) and A.B.C. Corp. (1-10), Civil Action No.
94-5827 (HAA) in the United States District Court, District of New Jersey. The
plaintiffs alleged various causes of action, including inefficient and wasteful
management of partnership assets relating to their investment in real estate and
oil and gas limited partnerships. AEPCO acts as a co-general partner in the oil
and gas limited partnership. The plaintiffs sought a rescission of their
investments, compensatory and punitive damages, and other relief. This case was
dismissed with prejudice as to all defendants in December 1995. The Company did
not bear any costs in the settlement of this litigation.

See Note 18 for a discussion of certain litigation filed against the
co-general partners of the NYLOG Programs in 1996 and the proposed liquidation
of the NYLOG Programs.

Cement I Unit -- Caddo County, Oklahoma. In 1991, an administrative
hearing was held by the Oklahoma Corporation Commission ("OCC") to establish the
cause of the saltwater contamination of the municipal water supply of the city
of Cyril, Oklahoma and to formulate a plan of abatement of the pollution.
Parties to the hearing included the current and former operators of the Cement I
Unit as well as the Company. The Company owns an 18.56% interest in the Cement I
Unit and controls an additional 6.42% interest through investment programs. In
August 1992, the administrative law judge granted the Company's motion to
dismiss on the grounds that the Company had not violated any statute, rule or
regulation of the OCC and that the evidence did not establish that the Company
caused any contamination of the aquifer. The ruling was subsequently affirmed by
the OCC in December 1992.

F-25
<PAGE> 93

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

In April 1995, the Court of Appeals issued a ruling affirming the Company's
dismissal from the proceeding. In rendering its April 1995 judgment, the Court
stated, however, that any claims which an operator wishes to make against any
non-operator (which could include the Company) pursuant to the plan of
unitization, for the non-operator's proportionate share of any costs incurred
pursuant to any remediation ultimately ordered, must be brought in District
Court in a new proceeding. To date, no such claims have been brought against the
Company.

In September 1995, the Supreme Court of Oklahoma granted a Writ of
Certiorari to review the case. However, in December 1995, the court reversed its
ruling and denied the petitions for certiorari. The dismissal of the Company
from this action is now final.

NORM RELATED PROCEEDINGS

The Company and certain subsidiaries, among other operators, have been
named as defendants in two lawsuits in Mississippi and three lawsuits in
Louisiana alleging various causes of action due to the alleged presence of
naturally occurring radioactive materials ("NORM") and other hazardous
substances. The plaintiffs allege that the NORM contamination is a result of oil
and gas operations conducted on properties operated or owned by the Company, its
subsidiaries and their predecessors in title, or NORM contaminated pipe
delivered to a pipe cleaning facility by the Company or its subsidiaries.

The Company has conducted a review of its operations with particular
attention to environmental compliance. The Company believes it has acted as a
prudent operator and is in compliance in all material respects with
environmental regulations. As part of the Company's continuing operations, the
Company has recorded site remediation costs of $541,000 and $2.4 million in 1995
and 1994, respectively. The Company anticipates it will incur additional costs
from time to time related to the continued assessment, testing, disposal, site
restoration and other activities in connection with the Company's environmental
proceedings. The Company will continue to vigorously contest liability under the
pending proceedings and seek to apportion any resulting liability under such
proceedings among the Company, its predecessor operators and other working
interest owners.

A brief summary of each of the lawsuits is presented below.

Bay Springs Field -- Jasper County, Mississippi. In May 1994, the Company
was served with a lawsuit filed by private landowners against the Company and
other defendants in the Circuit Court of Jasper County, Mississippi, First
Judicial District, based on the presence of NORM on the plaintiffs' property.
The plaintiffs allege that the NORM contamination is a result of oil and gas
operations conducted on properties operated by the Company and its predecessors
in title and on properties in which the Company does not own an interest. The
Company removed the lawsuit to federal court and obtained a ruling from the
court that allowed remediation of the property operated by the Company. The
lawsuit has since been remanded back to the Circuit Court of Jasper County.

The Company successfully obtained an order severing the claims against it
from claims against properties in which the Company does not own an interest.
The amount of damages sought against the Company is not known at this time since
the plaintiffs have failed to quantify such damages.

The Company has completed a NORM remediation program on the property and
the site has been restored. The Company believes that the completion of the
remediation effort has significantly reduced any basis for the plaintiffs'
damage claims and, although the Company cannot predict the outcome of this
proceeding, American Exploration does not expect the outcome of the case to have
a material adverse impact on its financial position or results of operations.

F-26
<PAGE> 94

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

Diamond Field -- Wayne County, Mississippi. The Company and a subsidiary
were served in May 1994 with a lawsuit in the Circuit Court of Wayne County,
Mississippi based on the presence of NORM and other hazardous materials arising
from oil and gas activities on certain tracts in the Diamond Field. Injunctive
relief and monetary and punitive damages are sought; however, the plaintiffs do
not specify the amount of damages being sought. In November 1994, the Court
denied a motion by the plaintiffs to enjoin the Company from remediating the
property without approval by the plaintiffs and issued a ruling that allowed the
Company to remediate the property without interference. The Company completed
remediation in February 1995. In January 1996, the plaintiffs dropped all
allegations of personal injury from their claims. The Company believes that the
completion of the remediation effort has significantly reduced any basis for the
plaintiffs' damage claims and, although the Company cannot predict the outcome
of this proceeding, American Exploration does not expect the outcome of the case
to have a material adverse impact on its financial position or results of
operations.

Fordoche Field -- Point Coupee Parish, Louisiana. In August 1994, a
Company subsidiary and affiliate were served with a lawsuit in the 18th Judicial
District Court, Point Coupee Parish, Louisiana. The plaintiffs alleged they
represented a class of plaintiffs damaged by oil and gas activities, including
damages caused by NORM, elevated levels of chlorides and other hazardous oil
field wastes and substances in the Fordoche Field and other fields operated by a
third party near Lottie, Louisiana. The class certification was never approved
by the court. The plaintiffs sought unspecified compensation for actual and
exemplary damages. The Company owns a minority interest and does not operate
this property. In January 1996, the case was dismissed with
prejudice against the Company and its affiliate at no cost to the Company.

51 Oil Corp. Facility. A Company subsidiary was served with two lawsuits
relating to the 51 Oil Corp. Facility near Lafayette, Louisiana. In 51 Oil Corp.
v. Adobe Resources Corp., et al., Civil Action No. 93-08548, filed in Civil
District Court in Orleans Parish, Louisiana, the plaintiff alleged that the
Company's subsidiary, among 65 other defendants, supplied pipe contaminated with
NORM to the plaintiff. The plaintiff alleged that the defendants failed to warn
the plaintiff of this condition, among other allegations, and sought
contribution by the defendants for the cost of remediation of its property as
well as other damages. The plaintiff's records indicate that the Company's
subsidiary supplied about one-half of one percent of the pipe to the facility.
The lawsuit was settled for $25,000 as to the Company's subsidiary in March 1995
and was dismissed with prejudice on April 12, 1995.

In Danny Broussard, et al. v. Adobe Resources Corp., et al., Civil Action
No. 94-8019, filed in July 1994 in Civil District Court in Orleans Parish,
Louisiana, the plaintiffs, an employee of 51 Oil Corp. and his family, alleged
that a Company subsidiary delivered pipe contaminated with NORM to 51 Oil Corp.
and that such actions caused the plaintiff to suffer various personal injuries.
The plaintiffs sought compensatory and punitive damages for both medical
expenses and other damages; however, the plaintiffs did not specify the amount
of damages being sought. The lawsuit was settled for $3,000 against the
Company's subsidiary, and the case was dismissed with prejudice on February 5,
1996.

F-27
<PAGE> 95

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(15) CASH FLOW INFORMATION

Supplemental cash flow information is presented below (in thousands):

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------------- -------------------
1993 1994 1995 1995 1996
------ -------- ------- ------ -------
<S> <C> <C> <C> <C> <C>
CASH PAYMENTS:
Interest, net of amounts capitalized
(a)............................... $6,931 $ 6,528 $ 5,638 $4,062 $ 1,854
Income taxes......................... 567 39 40 47 --
NONCASH INVESTING AND FINANCING
ACTIVITIES:
APPL Consolidation:
Acquisition of oil and gas
properties...................... $ -- $ 52,222 $ 1,198 $ -- $ 1,198
Other assets...................... -- 2,287 -- -- --
Liabilities assumed............... -- 535 -- -- --
Debt retired...................... -- 1,612 4,680 -- 4,680
American Exploration common stock
issued.......................... -- (56,230) (4,326) -- (4,326)
Gain on extinguishment of debt.... -- (426) (1,552) -- (1,552)
Issuance of common stock to
officers.......................... $1,237(b) $ -- $ -- $ -- $ --
</TABLE>

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

(a) The Company capitalized interest totaling $2.3 million in 1993 and $1.5
million in both 1994 and 1995, based on the Company's weighted average bank
borrowing rate for the period. Capitalized interest totaled $1.0 million and
$1.5 million for the first nine months of 1995 and 1996, respectively.

(b) Amount consists of notes receivable from officers totaling approximately
$230,000 and unearned compensation of approximately $1.0 million, which are
both recorded as reductions of stockholders' equity.

F-28
<PAGE> 96

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(16) INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

The Company's only industry segment is oil and gas exploration and
production. Information regarding the Company's operations by geographic area
for the last three years is presented below (in thousands):

<TABLE>
<CAPTION>
UNITED OTHER
STATES(A) CANADA(B) FOREIGN(C) CONSOLIDATED
--------- --------- ---------- ------------
<S> <C> <C> <C> <C>
Year Ended December 31, 1993
Sales to unaffiliated customers.................. $ 44,334 $ 5,255 $ -- $ 49,589
Income (loss) from operations.................... 844 822 (13,684) (12,018)
Identifiable assets.............................. 178,642 -- 6,956 185,598
Year Ended December 31, 1994
Sales to unaffiliated customers.................. $ 50,033 $ -- $ -- $ 50,033
Loss from operations............................. (44,727) -- (6,706) (51,433)
Identifiable assets.............................. 223,894 -- -- 223,894
Year Ended December 31, 1995
Sales to unaffiliated customers.................. $ 70,768 $ -- $ -- $ 70,768
Income from operations........................... 6,813 -- -- 6,813
Identifiable assets.............................. 176,030 -- -- 176,030
</TABLE>

- ---------------
(a) In 1994, the Company reported an impairment charge of $25.0 million related
to a change in accounting policy for impairment of proved oil and gas
properties. (See Note 1.)

(b) The Company sold all of its Canadian assets in mid-1993.

(c) Net losses related to the Company's leasehold interests in Oman and Tunisia
primarily reflect the write-off of these assets, which were sold in 1994.

F-29
<PAGE> 97

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(17) QUARTERLY RESULTS -- (UNAUDITED)

<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- ------- ------- --------
(IN THOUSANDS, EXCEPT FOR PER SHARE DATA)
<S> <C> <C> <C> <C>
Year Ended December 31, 1994 (a)
Oil and gas sales................................... $ 9,366 $11,145 $13,355 $ 16,167
Total revenues...................................... 9,433 11,442 13,831 16,653
Loss from operations................................ (11,329) (2,413) (4,035) (33,656)
Loss before extraordinary item...................... (12,809) (4,273) (5,608) (37,545)
Net loss............................................ (12,809) (2,231) (2,657) (37,119)
Net loss per common share:
Loss before extraordinary item...................... $ (1.88) $ (.67) $ (.78) $ (3.68)
Extraordinary gain on extinguishment of debt........ -- .29 .38 .04
-------- ------- ------- --------
Net loss per common share................... $ (1.88) $ (.38) $ (.40) $ (3.64)
======== ======= ======= ========
Year Ended December 31, 1995 (b)
Oil and gas sales................................... $ 17,832 $20,327 $16,890 $ 15,719
Total revenues...................................... 18,837 20,725 25,839 16,533
Income (loss) from operations....................... 1,308 2,897 7,263 (4,655)
Income (loss) before extraordinary item............. (495) 990 6,015 (5,033)
Net income (loss)................................... 1,961 990 6,015 (5,033)
Net income (loss) per common share:
Income (loss) before extraordinary item............. $ (.08) $ .05 $ .47 $ (.46)
Extraordinary gain on extinguishment of debt........ .21 -- -- --
-------- ------- ------- --------
Net income (loss) per common share.......... $ .13 $ .05 $ .47 $ (.46)
======== ======= ======= ========
</TABLE>

- ---------------
(a) In the first quarter of 1994, the Company recorded impairment expense of
$6.4 million for the write-off of American Exploration's remaining leasehold
interest in Tunisia. During the fourth quarter, the Company reported an
impairment charge of $25.0 million related to the change in accounting
policy for impairment of proved oil and gas properties. Also in the fourth
quarter, the Company recorded additional impairment expense of $1.4 million
associated with several properties on which no further exploratory work is
planned and a $2.0 million severance charge as a result of the APPL
Consolidation. In the second, third and fourth quarters of 1994, the Company
recorded extraordinary gains of $2.0 million, $3.0 million and $426,000,
respectively, which resulted from the elimination of nonrecourse debt
through the APPL Consolidation.

(b) In the first quarter of 1995, the Company recorded an extraordinary gain of
$2.5 million resulting from the elimination of debt through the APPL
Consolidation. In the third quarter of 1995, the Company recorded a gain on
the sale of the Sawyer Field of approximately $10.6 million, offset in part
by recognition of $2.8 million of dry hole expense on two wells. In the
fourth quarter of 1995, the Company recorded an impairment charge of $1.8
million related to impairment of an unproved property and recorded
additional dry hole expense of $1.3 million primarily related to one
offshore well.

Quarterly earnings per common share are based on the weighted average
number of shares outstanding during the quarter, and the sum of the quarters may
not equal annual earnings per common share. Earnings per common share have been
retroactively restated to reflect the one-for-ten reverse split of the Company's
common stock. (See Note 2.)

F-30
<PAGE> 98

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

(18) SUBSEQUENT EVENTS

NYLOG LITIGATION AND PROPOSED LIQUIDATION

The Company and its subsidiary, American Exploration Production Company
(together, the "American Exploration Parties"), along with New York Life and
several of its subsidiaries, have been named as defendants in a class action
complaint filed in the United States District Court for the Southern District of
Florida on March 18, 1996, styled Shea et al. v. New York Life Insurance Co., et
al. (Civil Action No. 96-0746) alleging generally that the defendants engaged in
fraudulent activities in connection with the marketing and sale of interests in
various limited partnerships, including the NYLOG Programs, and the subsequent
operation of such partnerships, breached implied covenants and fiduciary duties
owed to investors and violated various federal securities and state laws and
rules. The plaintiffs purport to represent a class of all persons who purchased
or otherwise assumed rights and title to interests in the partnerships that were
created, sponsored, marketed, sold, operated or managed by the defendants from
January 1, 1985 through March 18, 1996. The plaintiffs have asked for
compensatory damages for their lost original investment, plus interest, costs
(including attorneys' fees), punitive damages, disgorgement of any earnings,
compensation and benefits received by the defendants as a result of the alleged
actions and other unspecified relief to which plaintiffs may be entitled. The
lawsuit was preceded by two similar but separate lawsuits filed by the
plaintiffs in the District Courts in Harris County, Texas on January 11, 1996.

The defendants expressly deny any wrongdoing alleged in the complaints and
do not concede any liability or wrongdoing in connection with any of the facts
or claims that have been alleged against them in the lawsuits described above,
including any liability or wrongdoing in connection with the sale of the units
of limited partner interest in the partnerships. Nevertheless, to reduce the
burden of protracted litigation, the defendants have entered into a Stipulation
of Settlement (the "Settlement Agreement") with the plaintiffs because, in their
opinion, the settlement would (i) provide substantial benefits to the limited
partners in a manner consistent with New York Life's prior determination to wind
up the NYLOG Programs through orderly liquidation because the continuation of
the business no longer served the intended objectives of either the limited
partners or the defendants and to offer the limited partners an enhancement to
the liquidating distribution they would otherwise receive, (ii) provide an
opportunity to wind up the partnerships on a schedule favorable to the limited
partners and to resolve the issues raised by the lawsuits and (iii) reduce the
burdens and uncertainties associated with protracted litigation of the claims
underlying the lawsuits.

If the Settlement Agreement is approved by the Florida court and becomes
final, a limited partner of a limited partnership who participates in the
settlement will receive from an affiliate of New York Life a cash payment that,
together with prior distributions to such settling limited partner from such
limited partnership, will result in the settling limited partner having received
in the aggregate an amount at least equal to his total investment in such
partnership. If the proposed settlement becomes final, the defendants and
various other related parties will be released and discharged from any and all
claims a limited partner may have against the defendants in connection with the
partnerships. The American Exploration Parties will not be liable for any
payment of advances or refunds to the NYLOG investors.

On March 19, 1996, the Florida federal district court issued a hearing
order and certified the class for settlement purposes only and directed the
defendants to cause a class notice to be mailed to potential class members. The
Settlement Agreement is not yet final, is subject to a number of conditions and
may be terminated in certain circumstances.

F-31
<PAGE> 99

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION FOR THE NINE MONTH PERIODS ENDED SEPTEMBER 30, 1995 AND 1996 IS
UNAUDITED.)

arising out of Mancil's purchase of interests in certain NYLOG Programs
including, among other things, fraud, reckless and negligent misrepresentations,
and negligence in hiring, training and/or supervising a sales agent involved in
the sale of the NYLOG interests. Plaintiffs seek an unspecified amount of
compensatory and punitive damages and costs.

The American Exploration Parties and NYLIFE Inc. ("NYLIFE"), a subsidiary
of New York Life, have entered into an indemnity agreement (the "Indemnity
Agreement") pursuant to which NYLIFE has agreed to indemnify the American
Exploration Parties from and against any and all judgments or settlements
entered or reached in the NYLOG litigation described above, or any subsequent
lawsuits by investors in the NYLOG Programs based on claims and factual
allegations substantially similar to those contained in the original complaints
filed in state district court in Texas (collectively with the Mancil Litigation,
the "NYLOG Litigation"). Pursuant to the Indemnity Agreement, NYLIFE has assumed
control of the joint defense of the NYLOG Litigation at NYLIFE's expense
including, but not limited to, any settlement discussions or settlements.
Additionally, pursuant to the Indemnity Agreement, the American Exploration
Parties have agreed that if a settlement of the NYLOG Litigation occurs and in
connection therewith the assets of the NYLOG Programs are sold in liquidation of
the partnerships, the American Exploration Parties will be allocated 5% (which
represents AEPCO's initial capital contribution percentage) of revenues and net
proceeds from the sale of properties effective from and after February 1, 1996.
Based upon the terms of the Indemnity Agreement, the Company does not believe
that the NYLOG Litigation will have a material adverse impact on its financial
position or results of operations.
F-32
<PAGE> 100

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

CAPITALIZED COSTS

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Proved properties........................................................ $319,048 $265,953
Unproved oil and gas interests........................................... 24,405 26,074
-------- --------
Total capitalized costs................................................ 343,453 292,027
Less: Accumulated depreciation, depletion and amortization............. 153,509 146,188
-------- --------
Net capitalized costs.................................................. $189,944 $145,839
======== ========
</TABLE>

COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION
AND DEVELOPMENT ACTIVITIES

<TABLE>
<CAPTION>
UNITED
STATES FOREIGN TOTAL
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Year Ended December 31, 1993
Proved property acquisition costs........................... $ 4,596 $ 1,011 $ 5,607
Exploration costs........................................... 6,103 5,006 11,109
Development costs........................................... 8,786 686 9,472
Capitalized interest........................................ 1,390 956 2,346
-------- -------- --------
Total costs incurred................................ $ 20,875 $ 7,659 $ 28,534
======== ======== ========
Year Ended December 31, 1994
Proved property acquisition costs........................... $ 81,385 $ -- $ 81,385
Exploration costs........................................... 2,583 -- 2,583
Development costs........................................... 15,804 -- 15,804
Capitalized interest........................................ 1,496 -- 1,496
-------- -------- --------
Total costs incurred................................ $101,268 $ -- $101,268
======== ======== ========
Year Ended December 31, 1995
Property acquisition costs:
Proved................................................... $ 14,491 $ -- $ 14,491
Unproved................................................. 2,642 -- 2,642
Exploration costs........................................... 2,449 -- 2,449
Development costs........................................... 23,089 -- 23,089
Capitalized interest........................................ 1,468 -- 1,468
-------- -------- --------
Total costs incurred................................ $ 44,139 $ -- $ 44,139
======== ======== ========
</TABLE>

F-33
<PAGE> 101

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
UNITED
STATES FOREIGN TOTAL
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Year Ended December 31, 1993
Revenues.................................................... $ 44,334 $ 5,255 $ 49,589
Production and operating costs.............................. 14,088 1,910 15,998
Exploration expense......................................... 4,219 3,335 7,554
Depreciation, depletion and amortization.................... 20,192 1,861 22,053
Impairment expense.......................................... 773 10,202 10,975
Taxes other than income..................................... 3,687 42 3,729
Income tax expense.......................................... 505 -- 505
-------- -------- --------
Results of operations for producing activities...... $ 870 $(12,095) $ (11,225)
======== ======== ========
Year Ended December 31, 1994
Revenues.................................................... $ 50,033 $ -- $ 50,033
Production and operating costs.............................. 21,302 -- 21,302
Exploration expense......................................... 2,569 (10) 2,559
Depreciation, depletion and amortization.................... 28,062 -- 28,062
Impairment expense.......................................... 27,127 6,443 33,570
Taxes other than income..................................... 4,630 -- 4,630
Income tax benefit.......................................... (455) -- (455)
-------- -------- --------
Results of operations for producing activities...... $(33,202) $ (6,433) $(39,635)
======== ======== ========
Year Ended December 31, 1995
Revenues.................................................... $ 70,768 $ -- $ 70,768
Production and operating costs.............................. 24,515 -- 24,515
Exploration expense......................................... 4,826 -- 4,826
Depreciation, depletion and amortization.................... 29,100 -- 29,100
Impairment expense.......................................... 1,822 -- 1,822
Taxes other than income..................................... 4,928 -- 4,928
Income tax benefit.......................................... (121) -- (121)
-------- -------- --------
Results of operations for producing activities...... $ 5,698 $ -- $ 5,698
======== ======== ========
</TABLE>

OIL AND GAS RESERVE INFORMATION -- (UNAUDITED)

The following information summarizes the policies used by the Company in
preparing the accompanying oil and gas reserve disclosures, standardized measure
of discounted future net cash flows relating to proved oil and gas reserves and
the reconciliation of such standardized measure from period to period.

Proved reserves are estimated quantities of crude oil and natural gas which
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 proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.

The standardized measure of discounted future net cash flows from
production of proved reserves was developed by first estimating the quantities
of proved reserves and the future periods during which they are expected to be
produced based on year-end economic conditions. The estimated future cash flows
from proved reserves were then determined based on year-end prices, except in
those instances where fixed and determinable price escalations are included in
existing contracts. The effects of derivative transactions did not

F-34
<PAGE> 102

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

materially impact oil and gas prices as of December 31, 1995. Finally, future
cash flows were reduced by estimated production costs, costs to develop and
produce the proved reserves, and certain abandonment costs, all based on
year-end economic conditions and the estimated effect of future income taxes
based on the current tax law.

The standardized measure of discounted future net cash flows does not
purport to present, nor should it be interpreted to present, the fair value of
the Company's oil and gas reserves. An estimate of fair value would also take
into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES -- (UNAUDITED)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows........................................ $ 326,768 $ 502,989 $ 454,508
Future production and development costs.................... (147,481) (258,711) (209,094)
--------- --------- ---------
Future net cash flows before income taxes.................. 179,287 244,278 245,414
Future income taxes........................................ (4,528) (2,109) (2,892)
--------- --------- ---------
Future net cash flows after income taxes................... 174,759 242,169 242,522
Discount at 10% annual rate................................ (71,489) (101,463) (98,628)
--------- --------- ---------
Standardized measure of discounted future net cash flows... $ 103,270 $ 140,706 $ 143,894
========= ========= =========
</TABLE>

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS -- (UNAUDITED)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Balance, beginning of year.................................... $180,812 $103,270 $140,706
Sales and transfers of oil and gas produced, net of production
costs....................................................... (31,818) (24,101) (41,325)
Net changes in prices and production costs.................... (19,870) (67,753) 9,959
Extensions, discoveries and improved recoveries, net of future
production and development costs............................ 12,780 3,822 22,867
Purchases of minerals in place................................ 7,203 115,379 15,162
Sales of minerals in place.................................... (48,521) (451) (33,672)
Changes in estimated future development costs................. (5,325) 4,997 3,222
Development costs incurred during the year.................... 7,931 11,518 11,592
Revisions of previous quantity estimates...................... (15,967) (7,826) 3,857
Accretion of discount......................................... 18,269 10,476 14,230
Net change in future income taxes............................. 386 117 (444)
Changes in production rates (timing) and other................ (2,610) (8,742) (2,260)
-------- -------- --------
Balance, end of year.......................................... $103,270 $140,706 $143,894
======== ======== ========
</TABLE>

F-35
<PAGE> 103

AMERICAN EXPLORATION COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

RESERVE QUANTITY INFORMATION -- (UNAUDITED)

<TABLE>
<CAPTION>
UNITED STATES CANADA TOTAL
------------------ ------------------- -------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------- ------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES
Balance at December 31, 1992............... 8,031 123,373 1,392 120,713 9,423 244,086
Purchases of minerals in place........... 107 10,029 51 7,182 158 17,211
Extensions, discoveries and other
additions.............................. 326 10,157 -- 544 326 10,701
Revisions of previous estimates.......... (1,127) (13,642) -- -- (1,127) (13,642)
Sales of minerals in place............... (253) (13,400) (1,371) (124,897) (1,624) (138,297)
Production............................... (1,189) (11,794) (72) (3,542) (1,261) (15,336)
------ ------- ------ -------- ------ --------
Balance at December 31, 1993............... 5,895 104,723 -- -- 5,895 104,723
Purchases of minerals in place........... 5,153 108,075 -- -- 5,153 108,075
Extensions, discoveries and other
additions.............................. 128 12,825 -- -- 128 12,825
Revisions of previous estimates.......... (197) (22,467) -- -- (197) (22,467)
Sales of minerals in place............... (78) (235) -- -- (78) (235)
Production............................... (1,241) (16,241) -- -- (1,241) (16,241)
------ ------- ------ -------- ------ --------
Balance at December 31, 1994............... 9,660 186,680 -- -- 9,660 186,680
Purchases of minerals in place........... 1,225 18,846 -- -- 1,225 18,846
Extensions, discoveries and other
additions.............................. 1,435 17,318 -- -- 1,435 17,318
Revisions of previous estimates.......... 616 1,270 -- -- 616 1,270
Sales of minerals in place............... (792) (73,650) -- -- (792) (73,650)
Production............................... (1,680) (24,450) -- -- (1,680) (24,450)
------ ------- ------ -------- ------ --------
Balance at December 31, 1995............... 10,464 126,014 -- -- 10,464 126,014
====== ======= ====== ======== ====== ========
PROVED DEVELOPED RESERVES
Balance at December 31, 1993............... 5,018 71,623 -- -- 5,018 71,623
====== ======= ====== ======== ====== ========
Balance at December 31, 1994............... 8,697 127,838 -- -- 8,697 127,838
====== ======= ====== ======== ====== ========
Balance at December 31, 1995............... 9,474 98,590 -- -- 9,474 98,590
====== ======= ====== ======== ====== ========
</TABLE>

F-36
<PAGE> 104

INDEPENDENT AUDITORS' REPORT

To the Board of Directors
American Exploration Company:

We have audited the accompanying statements of oil and gas revenues and
direct lease operating expenses attributable to certain oil and gas properties,
acquired by American Exploration Company from Zilkha Energy Company (the Zilkha
I Properties), for each of the years in the three-year period ended December 31,
1995. These statements of oil and gas revenues and direct lease operating
expenses are the responsibility of American Exploration Company's management.
Our responsibility is to express an opinion on these statements of oil and gas
revenues and direct lease operating expenses 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 statements of oil and gas revenues and
direct lease operating expenses are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statements of oil and gas revenues and direct lease operating
expenses. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
presentation of the statements of oil and gas revenues and direct lease
operating expenses. We believe that our audits of the statements of oil and gas
revenues and direct lease operating expenses provide a reasonable basis for our
opinion.

The accompanying statements were prepared as described in note 1 for the
purpose of complying with certain rules and regulations of the Securities and
Exchange Commission (SEC) for inclusion in certain SEC regulatory reports and
filings and are not intended to be a complete financial presentation.

In our opinion, the accompanying statements of oil and gas revenues and
direct lease operating expenses present fairly, in all material respects, the
oil and gas revenues and direct lease operating expenses of the Zilkha I
Properties for each of the years in the three-year period ended December 31,
1995, in conformity with generally accepted accounting principles.

KPMG PEAT MARWICK LLP

Houston, Texas
September 26, 1996

F-37
<PAGE> 105

THE ZILKHA I PROPERTIES

STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995 AND THE PERIOD
JANUARY 1, 1996 THROUGH FEBRUARY 29, 1996 (UNAUDITED)
(IN THOUSANDS)

<TABLE>
<CAPTION>
JANUARY 1,
YEAR ENDED DECEMBER 31, 1996 THROUGH
---------------------------- FEBRUARY 29,
1993 1994 1995 1996
---- ------ ------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C>
Oil and gas revenues............................... $358 $1,291 $7,513 $1,964
Direct lease operating expenses.................... 35 148 662 109
---- ------ ------ ------------
Oil and gas revenues in excess of direct lease
operating expenses............................... $323 $1,143 $6,851 $1,855
==== ====== ====== ============
</TABLE>

See accompanying notes to the Statements of Oil and Gas Revenues and
Direct Lease Operating Expenses.

F-38
<PAGE> 106

THE ZILKHA I PROPERTIES

NOTES TO STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
AND THE PERIOD JANUARY 1, 1996 THROUGH FEBRUARY 29, 1996 (UNAUDITED)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

During March 1996, American Exploration Company (the "Company") purchased
from Zilkha Energy Company ("Zilkha") 25% of Zilkha's working interest in
certain oil and gas properties (the "Zilkha I Properties") located in the Gulf
of Mexico.

The statements of oil and gas revenues and direct lease operating expenses
include only the oil and gas revenues and direct lease operating expenses
attributable to the purchased interest in the Zilkha I Properties and are not
intended to be a complete set of financial statements. Oil and gas revenues and
direct lease operating expenses included herein are not necessarily
representative of future operations.

The accompanying statements of oil and gas revenues and direct lease
operating expenses were derived from the historical accounting records. Direct
lease operating expenses include payroll, lease and well repairs, maintenance
and other direct operating expenses.

In the opinion of management, the unaudited statement of oil and gas
revenues and direct lease operating expenses for the period January 1, 1996
through February 29, 1996 includes all material adjustments, which consist only
of normal recurring adjustments necessary for a fair presentation, and is not
necessarily indicative of the results for the entire year.

Omitted Historical Financial Information

Full historical financial statements, including general and administrative
expenses, interest expense and income tax expense, have not been presented
historically because the above properties were not accounted for or operated as
a separate division. Historical depletion expense has also not been included as
the basis in the properties has been adjusted in the purchase price allocation;
therefore, historical depletion will no longer be relevant.

Gas Imbalances

The sales method is used for accounting for gas imbalances. Under the sales
method, gas revenues are recorded when received; no adjustment is made for any
resulting imbalance positions.

(2) CAPITAL EXPENDITURES (UNAUDITED)

Development expenditures related to the Zilkha I Properties totaled
approximately $116,000 during the period January 1, 1996 through February 29,
1996 and $1,917,000, $16,709,000 and $8,944,000 for the years ended December 31,
1993, 1994 and 1995, respectively.

(3) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Oil and Gas Reserves

The following table shows estimates of proved reserves, net of royalty
interests, at December 31, 1993, 1994 and 1995 which were acquired by the
Company from Zilkha during March 1996. The information was compiled from reserve
reports prepared by William M. Cobb & Associates, Inc., Independent Petroleum
Engineering Consultants, as of January 1, 1996. No comparable estimates were
available for prior periods; therefore, reserves for December 31, 1993, 1994,
and 1995 have been calculated by adjusting the January 1, 1996 amounts only for
producing activities. Consequently, no revisions of previous estimates have been
reflected. Management emphasizes that the volumes of reserves shown below are
estimates, which, by their

F-39
<PAGE> 107

THE ZILKHA I PROPERTIES

NOTES TO STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
AND THE PERIOD JANUARY 1, 1996 THROUGH FEBRUARY 29, 1996 (UNAUDITED)

nature, are subject to revision. The estimates are made using all available
geological and reservoir data as well as production performance data. These
estimates are reviewed annually and revised, either upward or downward, as
warranted by additional performance data. The properties are located offshore
Louisiana.

Estimated Quantities of Oil and Gas Reserves:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
1993 1994 1995
------------------- ------------------- ---------------------
OIL (BBL) GAS (MCF) OIL (BBL) GAS (MCF) OIL (BBL) GAS (MCF)
------- -------- ------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year.......... 955,710 8,577,140 955,658 8,405,273 893,973 8,211,033
Production................. (52) (171,867) (61,685) (194,240) (301,229) (1,507,057)
------- --------- ------- --------- ------- ---------
End of year................ 955,658 8,405,273 893,973 8,211,033 592,744 6,703,976
======= ========= ======= ========= ======= =========
Proved developed reserves:
Beginning of year.......... 652,389 7,202,704 652,337 7,030,837 590,652 6,836,597
======= ========= ======= ========= ======= =========
End of year................ 652,337 7,030,837 590,652 6,836,597 289,423 5,329,540
======= ========= ======= ========= ======= =========
</TABLE>

Discounted Future Net Cash Flows

Estimates of future net cash flows from proved reserves were made in
accordance with Statement of Financial Accounting Standards No. 69, "Disclosures
about Oil and Gas Producing Activities." The amounts are shown in the following
table.

Estimated future cash inflows are computed by applying January 1, 1996
prices of oil and natural gas to year-end quantities of proved reserves. Future
price changes are considered only to the extent provided by contractual
arrangements. Estimated future development and production costs are determined
by estimating the expenditures to be incurred in developing and producing the
proved oil and gas reserves at the end of the year, based on January 1, 1996
costs and assuming continuation of existing economic conditions.

Historical supplemental oil and gas reserve information does not include
estimated future income tax expenses as such amounts are not relevant or
indicative of future taxes to be incurred by the Company.

Because of unpredictable variances in expenses and capital forecasts, crude
oil and natural gas price changes, largely influenced and controlled by U.S. and
foreign governmental actions, and the fact that the basis for such estimates
vary significantly, management believes the usefulness of these projections is
limited. Estimates of future net cash flows presented do not represent
management's assessment of future profitability or future cash flow.
Management's investment and operating decisions are based upon reserve estimates
that include proved reserves, and upon different price and cost assumptions from
those used here.

It should be recognized that applying current costs and prices and a ten
percent standard discount rate does not convey absolute value. The discounted
amounts arrived at are only one measure of the value of proved reserves.

F-40
<PAGE> 108

THE ZILKHA I PROPERTIES

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES:

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows...................................... $ 35,459 $ 34,168 $ 26,655
Future development costs................................. (28,600) (11,891) (2,947)
Future production costs.................................. (3,368) (3,220) (2,559)
-------- -------- --------
Future net cash inflows before income taxes.............. 3,491 19,057 21,149
10% discount factor...................................... (425) (2,320) (2,574)
-------- -------- --------
Standardized measure of discounted future net cash
inflows, before income taxes........................... $ 3,066 $ 16,737 $ 18,575
======== ======== ========
</TABLE>

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES:

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year.................. $ 1,666 $ 3,066 $ 16,737
Changes in future development costs...................... 1,917 16,709 8,944
Sales, net of production costs........................... (323) (1,143) (6,851)
Accretion of discount.................................... 167 307 1,674
Changes in production rates (timing) and other........... (361) (2,202) (1,929)
-------- -------- --------
Standardized measure, end of year........................ $ 3,066 $ 16,737 $ 18,575
======== ======== ========
</TABLE>

F-41
<PAGE> 109

INDEPENDENT AUDITORS' REPORT

The Sole Director
Zilkha Energy Company:

We have audited the accompanying statement of oil and gas revenues and
direct lease operating expenses attributable to certain oil and gas properties
(the Zilkha II Properties) to be acquired by American Exploration Company for
the year ended December 31, 1995. This statement of oil and gas revenues and
direct lease operating expenses is the responsibility of Zilkha Energy Company's
management. Our responsibility is to express an opinion on this statement of oil
and gas revenues and direct lease operating expenses 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 oil and gas revenues and
direct lease operating expenses is free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statement of oil and gas revenues and direct lease operating
expenses. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
presentation of the statement of oil and gas revenues and direct lease operating
expenses. We believe that our audit of the statement of oil and gas revenues and
direct lease operating expenses provides a reasonable basis for our opinion.

The accompanying statement was prepared as described in note 1 for the
purpose of complying with certain rules and regulations of the Securities and
Exchange Commission (SEC) for inclusion in certain SEC regulatory reports and
filings and is not intended to be a complete financial presentation.

In our opinion, the accompanying statement of oil and gas revenues and
direct lease operating expenses presents fairly, in all material respects, the
oil and gas revenues and direct lease operating expenses of the Zilkha II
Properties for the year ended December 31, 1995, in conformity with generally
accepted accounting principles.

KPMG PEAT MARWICK LLP

Houston, Texas
September 26, 1996

F-42
<PAGE> 110

THE ZILKHA II PROPERTIES

STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES
FOR THE YEAR ENDED DECEMBER 31, 1995 AND THE PERIOD
JANUARY 1, 1996 THROUGH SEPTEMBER 30, 1996 (UNAUDITED)
(IN THOUSANDS)

JANUARY 1,
YEAR 1996
ENDED THROUGH
DECEMBER 31, SEPTEMBER 30,
1995 1996
--------- -------------
<S> <C> <C>
(UNAUDITED)
Oil and gas revenues............................................... $ 2,886 $ 5,016
Direct lease operating expenses.................................... 1,265 814
------ ------
Oil and gas revenues in excess of direct lease operating
expenses......................................................... $ 1,621 $ 4,202
====== ======
</TABLE>

See accompanying notes to the Statements of Oil and Gas Revenues and
Direct Lease Operating Expenses.

F-43
<PAGE> 111

THE ZILKHA II PROPERTIES

NOTES TO STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying statements present the oil and gas revenues and direct
lease operating expenses of East Cameron 328 and High Island 116 (the Zilkha II
Properties) to be acquired by American Exploration Company (the Company) from
Zilkha Energy Company ("Zilkha"). The Zilkha II Properties are located in the
Gulf of Mexico. High Island 116 did not begin producing until the third quarter
of 1996; East Cameron 328 commenced production in March 1995.

The statements of oil and gas revenues and direct lease operating expenses
include only the oil and gas revenues and direct lease operating expenses
attributable to the Zilkha II Properties to be acquired by the Company and are
not intended to be a complete set of financial statements. Oil and gas revenues
and direct lease operating expenses included herein are not necessarily
representative of future operations.

In the opinion of management, the unaudited statement of oil and gas
revenues and direct lease operating expenses for the period January 1, 1996
through September 30, 1996 includes all material adjustments, which consist only
of normal recurring adjustments necessary for a fair presentation, and is not
necessarily indicative of the results for the entire year.

Omitted Historical Financial Information

Gas Imbalances

The sales method is used for accounting for gas imbalances. Under the sales
method, gas revenues are recorded when received; no adjustment is made for any
resulting imbalance position.

(2) CAPITAL EXPENDITURES (UNAUDITED)

Development expenditures related to the Zilkha II Properties totaled
approximately $4,478,000 and $5,052,000 for the year ended December 31, 1995 and
the period January 1, 1996 through September 30, 1996, respectively.

(3) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

Oil and Gas Reserves

The following table shows estimates of proved reserves, net of royalty
interests, at December 31, 1995 to be acquired by the Company from Zilkha during
September 1996. The information was compiled from reserve reports prepared by
William M. Cobb & Associates, Inc., Independent Petroleum Engineering
Consultants, as of January 1, 1996. Reserves for January 1, 1995 have been
calculated by adjusting the January 1, 1996 amounts only for producing
activities. Consequently, no revisions of previous estimates have been
reflected. Management emphasizes that the volumes of reserves shown below are
estimates, which, by their nature, are subject to revision. The estimates are
made using all available geological and reservoir data as well as

F-44
<PAGE> 112

THE ZILKHA II PROPERTIES

NOTES TO STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES -- (CONTINUED)

production performance data. These estimates are reviewed semi-annually and
revised, either upward or downward, as warranted by additional performance data.
The properties are located offshore Texas and Louisiana.

Estimated Quantities of Oil and Gas Reserves:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1995
--------------------------
GAS
OIL (BBL) (MCF)
--------- --------
<S> <C> <C>
Proved reserves:
Beginning of year............................... 3,696,551 741,355
Production...................................... (164,119) (194,342)
--------- --------
End of year..................................... 3,532,432 547,013
========= ========
Proved developed reserves:
Beginning of year............................... -- --
End of year..................................... 290,272 222,798
========= ========
</TABLE>

Discounted Future Net Cash Flows

Estimated future cash inflows are computed by applying year-end prices of
oil and natural gas to year-end quantities of proved reserves. Future price
changes are considered only to the extent provided by contractual arrangements.
Estimated future development and production costs are determined by estimating
the expenditures to be incurred in developing and producing the proved oil and
gas reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions.

F-45
<PAGE> 113

THE ZILKHA II PROPERTIES

NOTES TO STATEMENTS OF OIL AND GAS REVENUES AND
DIRECT LEASE OPERATING EXPENSES -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES:

<TABLE>
<CAPTION>
DECEMBER 31,
1995
------------
(IN THOUSANDS)
<S> <C>
Future cash flows................................................................ $ 58,496
Future development costs......................................................... (14,550)
Future production costs.......................................................... (13,327)
--------
Future net cash inflows before income taxes...................................... 30,619
10% discount factor.............................................................. (7,357)
--------
Standardized measure of discounted future net cash inflows, before income
taxes.......................................................................... $ 23,262
========
</TABLE>

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES:

<TABLE>
<CAPTION>
DECEMBER 31,
1995
------------
(IN THOUSANDS)
<S> <C>
Standardized measure, beginning of year.......................................... $ 21,092
Changes in estimated future development cost..................................... 4,478
Sales, net of production costs................................................... (1,621)
Accretion of discount............................................................ 2,109
Changes in production rates (timing) and other................................... (2,796)
--------
Standardized measure, end of year................................................ $ 23,262
========
</TABLE>

F-46
<PAGE> 114
[NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD]

APPENDIX A

October 8, 1996

Mr. Harold M. Korell
American Exploration Company
1331 Lamar, Suite 900
Houston, Texas 77010-3088

Dear Mr. Korell:

In accordance with your request, we have audited the estimates prepared
by American Exploration Company, as of June 30, 1996, of the proved reserves
and future net revenue to the American Exploration Company interest in certain
oil and gas properties located in the United States. The properties acquired
from Zilkha Energy Company (Zilkha) have not been included in this audit. These
estimates were prepared using constant prices and costs in accordance with the
guidelines of the Securities and Exchange Commission (SEC). The following table
sets forth American Exploration Company's estimates of the proved reserves and
future net revenue for the audited properties as of June 30, 1996:

<TABLE>
<CAPTION>
Net Reserves Future Net Reserve
--------------------------- -----------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ------------------ ----------- ----------- ------------ -------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 8,158,296 93,182,487 $216,317,171 $139,725,306
Non-Producing 672,104 13,124,776 27,186,640 14,288,544
Proved Undeveloped 1,208,762 21,165,634 49,176,748 19,232,145
---------- ----------- ------------ ------------
Total Proved 10,039,162 127,472,897 $292,680,559 $173,245,995
</TABLE>

The oil reserves shown include crude oil, condensate, and gas plant
liquids. Oil volumes are expressed in barrels which are equivalent to 42 United
States gallons. Gas volumes are expressed in thousands of standard cubic feet
(MCF) at the contract temperature and pressure bases.

When compared on a field-by-field basis, some of the estimates of
American Exploration Company are greater and some are lesser than the estimates
of Netherland, Sewell & Associates, Inc.; however, in our opinion, the
estimates of American Exploration Company's net proved oil and gas reserves and
future net revenue are in the aggregate reasonable and have been prepared in
accordance with generally accepted petroleum engineering and evaluation
principles. These principles are set forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information promulgated by the
Society of Petroleum Engineers. We are satisfied with the methods and procedures

A-1
<PAGE> 115
[NSAI LOGO]

utilized by American Exploration Company in preparing the June 30, 1996
estimates and saw nothing of an unusual nature that would cause us to take
exception with the estimates, in the aggregate, as prepared by American
Exploration Company.

The estimated reserves and future revenue shown herein are for proved
developed producing, proved developed non-producing, and proved undeveloped
reserves. Our audit did not include consideration of probable or possible
reserves which may exist for these properties, nor did it include any
consideration of undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.

It should be understood that our audit does not constitute a complete
reserve study of American Exploration Company's oil and gas properties. Our
audit consisted of a detailed review of fields constituting the top 83 percent
of American Exploration Company's total proved present worth discounted at 10
percent, as of June 30, 1996, excluding the March and September 1996 Zilkha
acquisition properties. In our audit, we accepted without independent
verification the accuracy and completeness of the historical information and
data furnished by American Exploration Company with respect to ownership
interest, oil and gas production, well test data, oil and gas prices,
historical costs of operation and development, and any agreements relating to
current and future operations of the properties and sales of production.
However, if in the course of our examination something came to our attention
which brought into question the validity or sufficiency of any such information
or data, we did not rely on such information or data until we had
satisfactorily resolved our questions relating thereto or had independently
verified such information or data.

Oil prices used by American Exploration Company are based on a June
1996 average West Texas Intermediate posted price of $18.93 per barrel,
adjusted by lease for gravity, transportation fees, and regional posted price
differentials, and are held constant in accordance with SEC guidelines.

Gas prices used by American Exploration Company are based on either the
most current price available for each lease, adjusted to a June 1996 regional
spot market price, or the contract price. In accordance with SEC guidelines,
fixed and determinable price increases stipulated by existing contracts are
allowed. Prices used for Bowdoin Field, Montana, are held constant through
December 31, 1996, then escalated 4 percent on January 1 of each year to a
maximum of $7.49 per MMBTU. All other gas prices are held constant throughout
the life of the properties.

Lease and well operating costs are based on operating expense records
of American Exploration Company. These costs include the per-well overhead
expenses allowed under joint operating agreements along with costs estimated to
be incurred at and below the district and field levels. Headquarters general
and administrative overhead expenses of American Exploration Company are not
included. Lease and well operating costs are held constant in accordance with
SEC guidelines. Capital costs are included as required for workovers, new
development wells, and production equipment.

It is our understanding that American Exploration Company's estimates
of reserves and future revenue do not include adjustments for the settlement of
any potential gas volume and value imbalances which may have resulted from
overdelivery or underdelivery to the American Exploration Company

A-2
<PAGE> 116

[NSAI LOGO]

interest. The projections are based on American Exploration Company receiving
its net revenue interest share of estimated future gross gas production.

We are independent petroleum engineers and geologists with respect to
American Exploration Company as provided in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information promulgated by the
Society of Petroleum Engineers. We do not own an interest in these properties
and are not employed on a contingent basis.

Very truly yours,

/s/ CLARENCE NETHERLAND

GLB:DMS

A-3

<PAGE> 117
[WILLIAM M. COBB & ASSOCIATES, INC. LETTERHEAD]

October 4, 1996

Mr. Harold Korell
American Exploration Company
1331 Lamar, Suite 900
Houston, Texas 77010-3088

Dear Mr. Korell:

This summary letter report presents the results of our evaluation of the proved
oil and gas reserves and future net income attributable to the interest of
American Exploration Company (AEC) in seven oil and gas fields located in
Federal Offshore Waters in the Gulf Mexico. The AEC interests were acquired
from Zilkha Energy Company in two separate acquisitions during 1996. The
summary results presented herein were taken from our detailed reserve report
dated October 4, 1996.

Table 1 summarizes our estimate of the proved oil and gas reserves and their
pre-Federal Income Tax values undiscounted and discounted at ten percent for
the combined March and September 1996 acquisitions. Values shown are determined
utilizing June 30, 1996 hydrocarbon prices as required by SEC guidelines. The
discounted present worth of future income values shown in Table 1 or in other
portions of this report are not intended to necessarily represent an estimate
of fair market value.

TABLE 1

AEC NET RESERVES AND VALUE AS OF JUNE 30, 1996
MARCH AND SEPTEMBER 1996 ACQUISITIONS
SEC PRICING

<TABLE>
<CAPTION>
Net Reserves Future Net Pre-Tax Income
--------------------- ----------------------------------
Oil Gas Undiscounted Discounted at 10%
Reserve Category (MBBL) (MMCF) M$ M$
- ---------------- ------ ------ ------------ -----------------
<S> <C> <C> <C> <C>
Proved
Producing 561 6,669 20,343 17,893
Non-Producing 602 60 8,181 4,792
Undeveloped 3,190 20,051 58,348 43,951
----- ------ ------ ------
Total Proved 4,353 26,780 86,872 66,636
</TABLE>

A-4
<PAGE> 118
Page 2

Oil (Condensate) volumes are expressed in thousands of stock tank barrels
(MBBL). A stock tank barrel is equivalent to 42 United States gallons. Gas
volumes are expressed in millions of standard cubic feet (MMCF) as determined
at 60(degrees) Fahrenheit and the legal pressure base prevailing in the state
in which the reserves are located.

Table 2 presents summary reserve and cash flow information for the five
properties acquired in the March 1996 Acquisition.

TABLE 2

AEC NET RESERVES AND VALUE AS OF JUNE 30, 1996
MARCH 1996 ACQUISITION
SEC PRICING

<TABLE>
<CAPTION>
Net Reserves Future Net Pre-Tax Income
--------------- --------------------------------
Oil Gas Undiscounted Discounted at 10%
Reserve Category (MBBL) (MMCF) M$ M$
- ---------------- ------ ------ ------------ -----------------
<S> <C> <C> <C> <C>
Proved
Producing 335 6,604 16,663 14,499
Non-Producing 0 0 0 0
Undeveloped 142 1,262 3,448 3,031
--- ----- ------ ------
Total Proved 477 7,866 20,111 17,530
</TABLE>

Table 3 presents similar information for the September 1996 Acquisition which
includes interests in two properties.

TABLE 3

AEC NET RESERVES AND VALUE AS OF JUNE 30, 1996
SEPTEMBER 1996 ACQUISITION
SEC PRICING

<TABLE>
<CAPTION>
Net Reserves Future Net Pre-Tax Income
--------------- --------------------------------
Oil Gas Undiscounted Discounted at 10%
Reserve Category (MBBL) (MMCF) M$ M$
- ---------------- ------ ------ ------------ -----------------
<S> <C> <C> <C> <C>
Proved
Producing 226 65 3,680 3,394
Non-Producing 602 60 8,181 4,792
Undeveloped 3,048 18,789 54,900 40,920
----- ------ ------ ------
Total Proved 3,876 18,914 66,761 49,106
</TABLE>

A-5
<PAGE> 119
Page 3

DISCUSSION

The AEC properties are located in Federal waters offshore Louisiana and Texas
in the Gulf of Mexico. Interests in E. Cameron 129, W. Cameron 254, High Island
45, S. Marsh Island 133, and N. Padre Island 996 were purchased from Zilkha
Energy Company in March 1996 (March 1996 Acquisition). The AEC interests in
High Island 116 and E. Cameron 328 were purchased from Zilkha Energy Company
effective September 15, 1996 (September 1996 Acquisition). At the request of
AEC, these interests are included in this report as if they were owned on June
30, 1996.

The High Island 116 property was not producing at June 30, 1996. The property
was awaiting the installation of a production platform, and as such, the
reserves were classified as proved undeveloped (PUD). The production platform
has since been installed and the High Island 116 No. A-1 well was placed on
production on July 31, 1996. The well is currently producing at a rate of
47,500 MCF and 712 barrels of condensate per day.

RESERVE METHODOLOGY

Reserve calculations for the AEC properties are based on actual production and
pressure performance when sufficient historical data is available and
applicable. For properties with limited production performance data and for
those producing under a natural water-drive mechanism, reserves are determined
utilizing the volumetric technique. To perform the volumetric calculations, we
analyzed well logs provided by AEC to determine reservoir properties such as
porosity, water saturation, and net pay thickness. Areal extent and reservoir
bulk volume are determined from structure and net pay isopach maps provided by
AEC. We have studied the AEC maps, and in certain instances, we modified the
maps based on our interpretation of available well logs. It is noted that
reserve volumes calculated using the volumetric technique are generally less
reliable than those supported by actual performance trends and, as such, should
be considered to contain a higher element of risk.

ECONOMIC PROJECTIONS

Our detailed reserve report contains reserve and cash flow projections for each
AEC property, the results of which are summarized in Tables 1 through 3 of this
letter. The undiscounted future net pre-tax income presented in these tables is
the future net oil and gas revenue after deducting any applicable severance
taxes, ad valorem taxes, operating costs, and capital costs (including
abandonment costs). All economic evaluations are made without consideration of
Federal Income Taxes.

OTHER

The proved reserves included in this summary letter report conform to the
definition as set forth in the Securities and Exchange Commission's Regulation
S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting
Bulletins.

A-6
<PAGE> 120
Page 4

We have not made any field examination of the AEC properties. Therefore,
operating ability and condition of the production equipment have not been
considered. No consideration was given in this report to potential
environmental liabilities which may exist, nor were any costs included for
potential liability to restore and clean up damages, if any, caused by past
operating practices.

In evaluating the information at our disposal concerning this appraisal, we
have excluded from our consideration all matters as to which legal or
accounting interpretation, rather than engineering, may be controlling. As in
all aspects of oil and gas evaluation, there are uncertainties inherent in the
interpretation of engineering data and such conclusions necessarily represent
only informed professional judgments.

The reserves included in this summary letter report are estimates only and
should not be construed as being exact quantities. The revenues from such
reserves and the actual costs related thereto could be more or less than the
estimated amounts. Because of governmental policies and uncertainties of
supply and demand, the prices actually received for the reserves included in
this report, and the costs incurred in recovering such reserves, may vary from
the price and cost assumptions in this report. In any case, estimates of
reserves may increase or decrease as a result of future operations.

Titles to the appraised properties have not been examined by William M. Cobb &
Associates, Inc., nor has the actual degree of interest owned been
independently confirmed. The data used in our evaluation were obtained from
American Exploration Company and the nonconfidential files of William M. Cobb &
Associates, Inc. and were considered accurate. Basic field performance data
together with our engineering work sheets are maintained on file in our office.

Very truly yours,

WILLIAM M. COBB & ASSOCIATES, INC.

/s/ FRANK J. MAREK
---------------------------------
Frank J. Marek
Vice President

A-7
<PAGE> 121

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

NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFER MADE BY THIS PROSPECTUS, AND, IF GIVEN
OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED BY THE COMPANY, THE SELLING STOCKHOLDERS OR ANY OF THE
UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF ANY OFFER TO BUY ANY SECURITY OTHER THAN THE SHARES OF COMMON
STOCK OFFERED BY THIS PROSPECTUS, NOR DOES IT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF ANY OFFER TO BUY THE SHARES OF COMMON STOCK OFFERED BY THIS
PROSPECTUS BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS
NOT AUTHORIZED OR IN WHICH THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER
OR SOLICITATION TO SUCH PERSON. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY
SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT
THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS
DATE.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 10
The Company........................... 14
Use of Proceeds....................... 14
Price Range of Common Stock and
Dividend Policy..................... 15
Capitalization........................ 16
Pro Forma Condensed Consolidated
Financial Statements................ 17
Selected Financial Data............... 23
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 24
Business.............................. 33
Management............................ 48
Security Ownership of Management and
Certain Beneficial Owners........... 50
Selling Stockholders.................. 52
Executive Compensation................ 53
Certain Relationships and Related
Transactions........................ 56
Description of Capital Stock.......... 58
Underwriting.......................... 62
Legal Matters......................... 63
Experts............................... 63
Available Information................. 63
Glossary of Certain Oil and Gas Terms. 65
Index to Financial Statements......... F-1
Reports of Independent Petroleum
Engineers........................... A-1
</TABLE>

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3,927,055 Shares

[American Exploration Logo]

AMERICAN EXPLORATION

COMPANY

Common Stock

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

PROSPECTUS

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

PRUDENTIAL SECURITIES INCORPORATED
DILLON, READ & CO. INC.
A.G. EDWARDS & SONS, INC.
October 31, 1996

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