DOMAIN ENERGY CORP, 424B4, 1997-06-25

DOMAIN ENERGY CORP
424B4, 1997-06-25
CRUDE PETROLEUM & NATURAL GAS

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DOMAIN ENERGY CORPORATION

6,000,000 Shares
Common Stock
($.01 par value)

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

All of the shares of Common Stock, $.01 par value (the "Common Stock"), of
Domain Energy Corporation (the "Company") offered hereby are being sold by
the Company (the "Offering"). Concurrently with consummation of the Offering,
the Company will sell 643,037 shares of Common Stock, at a price per share
equal to the Price to Public set forth below, to First
Reserve Fund VII, Limited Partnership ("Fund VII") for an aggregate
purchase price of $8,681,000. Prior to the Offering, there has been no
public market for the Common Stock of the
Company. For information relating to the factors considered in
determining the initial public offering price, see
"Underwriting." The Common Stock has been approved for
listing on the New York Stock Exchange, subject to
notice of issuance, under the symbol "DXD."

FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH
AN INVESTMENT IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 11
HEREIN.

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.

UNDERWRITING
DISCOUNTS
PRICE TO AND PROCEEDS TO
PUBLIC COMMISSIONS COMPANY(1)
---------------------------------------
Per Share.............................. $13.50 $0.945 $12.555
Total(2)............................... $81,000,000 $5,670,000 $75,330,000

(1) Before deduction of expenses payable by the Company estimated at $1,000,000.

(2) The Company has granted the Underwriters an option, exercisable for 30 days
from the date of this Prospectus, to purchase a maximum of 900,000
additional shares to cover over-allotments of shares. If the option is
exercised in full, the total Price to Public will be $93,150,000,
Underwriting Discounts and Commissions will be $6,520,500, and Proceeds to
Company will be $86,629,500. See "Underwriting."

The shares of Common Stock are offered by the several Underwriters when, as
and if issued by the Company, delivered to and accepted by the Underwriters and
subject to their right to reject orders in whole or in part. It is expected that
the shares of Common Stock offered hereby will be ready for delivery on or about
June 27, 1997, against payment in immediately available funds.

CREDIT SUISSE FIRST BOSTON
PAINEWEBBER INCORPORATED
PRUDENTIAL SECURITIES INCORPORATED
MORGAN KEEGAN & COMPANY, INC.

Prospectus dated June 23, 1997
<PAGE>
[The paper version of this Prospectus contains a map of the Gulf of Mexico
and the Gulf Coast of Texas, Louisiana and Mississippi, which indicates the
locations of the Company's oil and gas properties in such region.]

CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANS- ACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING OVER-ALLOTMENT OF COMMON STOCK, PURCHASES OF THE COMMON STOCK TO
STABILIZE ITS MARKET PRICE, PURCHASES OF THE COMMON STOCK TO COVER SOME OR ALL
OF A SHORT POSITION IN THE COMMON STOCK MAINTAINED BY THE UNDERWRITERS AND THE
IMPOSITION OF PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE
"UNDERWRITING."

<PAGE>
PROSPECTUS SUMMARY

THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE DETAILED
INFORMATION AND FINANCIAL STATEMENTS AND THE NOTES THERETO APPEARING ELSEWHERE
IN THIS PROSPECTUS. CERTAIN TERMS RELATING TO THE OIL AND GAS BUSINESS ARE
DEFINED IN THE "GLOSSARY" SECTION OF THIS PROSPECTUS. UNLESS THE CONTEXT
INDICATES OTHERWISE, REFERENCES IN THIS PROSPECTUS TO "DOMAIN" OR THE "COMPANY"
ARE TO DOMAIN ENERGY CORPORATION, A DELAWARE CORPORATION, AND ITS SUBSIDIARIES,
WHICH SUBSIDIARIES COMPRISE THE COMPANY'S PREDECESSOR BUSINESS UNIT. UNLESS THE
CONTEXT INDICATES OTHERWISE, THE DISCUSSION IN THIS PROSPECTUS REFLECTS A
754-FOR-ONE STOCK SPLIT EFFECTED IMMEDIATELY PRIOR TO CONSUMMATION OF THE
OFFERING AND ASSUMES THAT THE UNDERWRITERS' OVER-ALLOTMENT OPTION WITH RESPECT
TO THE OFFERING IS NOT EXERCISED. UNLESS OTHERWISE INDICATED, THE PRO FORMA
INFORMATION PRESENTED IN THIS PROSPECTUS GIVES EFFECT TO THE ACQUISITION, THE
FUNDS ACQUISITION AND THE MICHIGAN DISPOSITION (AS SUCH TERMS ARE DEFINED
BELOW), THE PURCHASE OF COMMON STOCK BY THE COMPANY'S EMPLOYEES IN 1997, THE
GRANT OF OPTIONS TO PURCHASE COMMON STOCK TO THE COMPANY'S EMPLOYEES IN 1997,
THE PURCHASE OF COMMON STOCK BY FIRST RESERVE FUND VII, LIMITED PARTNERSHIP
CONCURRENTLY WITH CONSUMMATION OF THE OFFERING AND THE APPLICATION OF THE NET
PROCEEDS OF THE OFFERING AS DESCRIBED IN "USE OF PROCEEDS." THE ESTIMATES OF THE
COMPANY'S PROVED RESERVES AS OF DECEMBER 31, 1996 SET FORTH IN THIS PROSPECTUS
ARE BASED ON THE REPORTS OF DEGOLYER AND MACNAUGHTON AND, IN THE CASE OF THE
COMPANY'S WEST DELTA 30 FIELD AND FORMER MICHIGAN PROPERTIES, OTHER THIRD-PARTY
PETROLEUM ENGINEERS. UNLESS OTHERWISE INDICATED, THE OPERATING AND RESERVE DATA
SET FORTH HEREIN DOES NOT INCLUDE THE RESERVES OR RESERVE VALUE ATTRIBUTABLE TO
THE COMPANY'S INDEPENDENT PRODUCER FINANCE PROGRAM.

THE COMPANY

Domain is an independent oil and gas company engaged in the exploration,
development, production and acquisition of domestic oil and natural gas
properties, principally in the Gulf Coast region. The Company complements these
activities with its Independent Producer Finance Program (the "IPF Program")
pursuant to which it invests in oil and natural gas reserves through the
acquisition of term overriding royalty interests. During 1996, approximately 92%
of the Company's revenue was generated by oil and natural gas sales and
approximately 8% of the Company's revenue was generated by the IPF Program. The
Company's future growth will be driven by development, exploitation and
exploration drilling on its existing properties, by the continuation of an
opportunistic acquisition strategy in the Gulf Coast region and by further
expansion of the IPF Program.

The Company was formed in December 1996 by the management of Tenneco
Ventures Corporation and an affiliate of First Reserve Corporation to acquire
(the "Acquisition") Tenneco Ventures Corporation and certain of its affiliates
(collectively, "Tenneco Ventures"). Senior management of the Company established
Tenneco Ventures in 1992 as a separate business unit of its former parent,
Tenneco Inc. ("Tenneco"), to engage in exploration and production, oil and gas
program management, producer financing and related activities. All of the
Company's executive officers are veterans of the Tenneco organization, and 11 of
the Company's 19 technical personnel have Tenneco Oil Company backgrounds.
Approximately 85% of the Company's employees, including all of its management,
have purchased shares of Common Stock in the Company.

During the last four years, the Company has grown primarily through the
opportunistic acquisition of Gulf of Mexico properties and the subsequent
development, exploitation and exploration of these properties, resulting in
substantial increases in its reserves and production. The Company believes that
its acquisition costs, lease operating costs and net general and administrative
costs on a per Mcfe basis are low relative to other companies operating
principally in the Gulf Coast region. From 1994 through 1996, the Company
completed 11 acquisitions aggregating $106.9 million, with an average cost of
proved reserves estimated at the time of acquisition of $0.48 per Mcfe. Eight of
the 11 acquisitions were Gulf Coast region properties. In 1996 the Company
achieved a lease operating expense of $0.42 per Mcfe of production and a net
general and administrative expense (excluding Tenneco overhead allocations) of
$0.12 per Mcfe of production.

3
<PAGE>
The Company's pro forma estimated net proved reserves as of December 31,
1996 were 153.8 Bcfe, and its pro forma average daily production during 1996 was
85.6 MMcfe, each of which represents a twelvefold increase from levels in 1993.
Approximately 54% of these reserves were natural gas, and approximately 67% of
proved reserves were classified as proved developed producing. On a pro forma
basis as of December 31, 1996, the Company had a PV-10 Reserve Value of $213.0
million, which does not include reserve value attributable to the IPF Program.

Through the IPF Program, the Company complements its exploration and
production activities by providing capital to independent producers in return
for term overriding royalty interests in oil and gas properties owned by such
producers. From its inception in 1993 through December 31, 1996, the IPF Program
has generated an average return on net assets of approximately 19%. In addition,
the Company believes that the IPF Program offers a lower level of reserve,
production and price risk than that associated with working interest ownership.
From inception through December 31, 1996, the Company completed 40 transactions
under its IPF Program. At December 31, 1996, based on Company estimates and
assuming prices of $2.10 per Mcf of natural gas and $21.00 per Bbl of oil, the
net present value attributable to IPF Program assets was $25.4 million.

The Company reported net income of $7.0 million, $0.5 million and $0.4
million in 1996, 1995 and 1994, respectively. The Company reported unaudited net
loss of $0.3 million and unaudited net income of $2.8 million for the
three-month periods ended March 31, 1997 and 1996, respectively. Based on
unaudited financial information available to the Company for the period from
April 1, 1997 to the date of this Prospectus, the Company estimates that it will
report net income (loss) on approximately a "break-even" basis for the
three-month period ended June 30, 1997. Pro forma net income for the year ended
December 31, 1996 was $11.8 million. See "-- Summary Historical and Pro Forma
Combined and Consolidated Financial Data."

The Company generated earnings before stock compensation expense, interest,
income taxes, depreciation, depletion and amortization ("EBITDA") plus IPF
Program return of capital of $41.1 million in 1996, $26.2 million in 1995 and
$7.7 million in 1994. IPF Program return of capital was $4.6 million in 1996,
$2.6 million in 1995 and $3.5 million in 1994. The Company's 1996 pro forma
EBITDA plus IPF Program return of capital was $55.5 million.

The Company's Board of Directors has authorized a capital budget of $125.0
million for 1997. These planned expenditures consist of $29.0 million for
development and exploration expenditures, $36.0 million for IPF Program
investments and $60.0 million for acquisitions in the Company's core operating
area, $30.0 million of which is pending. See " -- Certain Transactions -- The
Funds Acquisition."

BUSINESS STRATEGY

The Company's objective is to maximize shareholder value by growing
reserves, production, cash flow and earnings through the opportunistic
acquisition of Gulf Coast region properties with underexploited value. The
Company applies 3-D seismic and other advanced technologies to development,
exploitation and exploration. These activities are complemented by the continued
expansion of the IPF Program. Fundamental to the execution of the Company's
strategy is its foundation of experienced technical talent strengthened by a
high level of financial, transactional and risk-management expertise resulting,
in part, from the former association of the Company and its employees with
Tenneco. Following the Offering, the Company will be in a strong financial
position to pursue acquisitions and other growth opportunities.

4
<PAGE>
region allow continued access to new opportunities. This geographic focus has
enabled the Company to build and utilize a base of region-specific geological,
geophysical, engineering and production expertise. The Company's geographic
focus allows it to manage a large asset base with relatively few employees, thus
permitting the Company to control expenses and add Gulf of Mexico production at
a relatively low incremental cost. The Company engages in IPF Program activities
throughout the onshore regions of the United States, with a principal geographic
focus in the Gulf Coast region.

ACQUISITION OF PROPERTIES WITH UNDEREXPLOITED VALUE. The Company employs an
acquisition strategy targeted primarily at purchases of Gulf Coast region
producing properties from major oil companies and large independents. These
properties provide opportunities to increase reserves, production and cash flow
through development and exploitation drilling and lease operating expense
reduction. The Company manages its acquired properties by working proactively
with its joint interest partners to accelerate development, identify
exploitation opportunities and implement cost controls on these properties.

DEVELOPMENT, EXPLOITATION AND EXPLORATION. The Company integrates its
reservoir and production engineering expertise with its geologic and seismic
interpretation abilities to enhance the results of its exploration and
production business. The Company applies workovers, recompletions, secondary
recovery operations and other production enhancement techniques on its existing
properties to increase recoverable reserves, production and cash flow.
Additionally, the Company uses advanced technology in both its development and
exploration activities to reduce drilling risks and finding costs and to
prioritize its drilling prospects based on return potential. The Company
utilizes 3-D seismic data to develop the majority of its drilling opportunities.
Eighty-five percent of the wells in which the Company participated in 1996 were
developed using 3-D seismic data. The Company's ability to integrate geophysics
with detailed geology, reservoir engineering and production engineering allows
it to identify multiple development and exploratory prospects in mature
producing fields that were not identified through earlier technologies. The
Company currently employs six geoscientists with an average experience level of
more than 16 years and operates two geophysical workstations interpreting 3-D
seismic data over twelve fields and six exploratory programs. The Company
intends to expand its geoscience team in 1997.

The Company has assembled a multiyear inventory of development,
exploitation and exploratory drilling opportunities in the Gulf Coast region and
has identified more than 70 drilling and recompletion opportunities for 1997.
Most of the properties comprising this inventory are located in fields that have
well-established production histories. The Company believes these properties may
yield significant additional recoverable reserves through the application of
advanced exploration and development technologies. The Company participated in
the drilling of nine development wells and 33 exploratory wells in 1996, of
which 78% and 61%, respectively, were successful.

CONTINUED EXPANSION OF THE IPF PROGRAM. The Company has leveraged its
expertise in oil and gas reserve appraisal and evaluation to develop and grow
the IPF Program. The Company believes this program offers an attractive
risk/reward balance and stable earnings. The oil and gas companies that
establish a relationship with the Company through the IPF Program often come to
view the Company as a prospective working interest partner for their drilling or
acquisition projects. Management believes that the investment opportunities,
market information and business relationships generated as a result of the IPF
Program provide the Company with a strategic advantage over other independent
oil and gas companies that are not engaged in this business. As a result of the
Company's efficiency in originating and closing IPF Program transactions in the
$0.5 to $5.0 million range, the Company currently encounters only limited
competition from alternate sources of capital for investment in quality
properties and projects of independent oil and gas companies.

The Company has budgeted $36.0 million for investment in IPF Program
transactions in 1997. The Company closed six IPF Program transactions in the
first quarter of 1997 for an aggregate of $9.2 million. In addition, the Company
is currently evaluating over 30 transactions, all of which satisfy the Company's
initial screening criteria.

5
<PAGE>
CERTAIN TRANSACTIONS

ACQUISITION OF COMMON STOCK BY FUND VII. Concurrently with consummation of
the Offering, First Reserve Fund VII, Limited Partnership, the Company's
principal stockholder ("Fund VII"), has agreed to purchase 643,037 shares of
Common Stock, at a price per share equal to the Price to Public set forth on the
cover of this Prospectus, for an aggregate purchase price of $8,681,000 (the
"Concurrent Sale"). See "Transactions with Management and First Reserve --
Acquisition of Common Stock by Fund VII."

THE FUNDS ACQUISITION. The Company previously sponsored and managed two oil
and gas investment programs (collectively, the "Funds") for institutional
investors. The Company has entered into a definitive agreement with the
investors in the Funds to acquire certain property interests from such investors
upon consummation of the Offering (the "Funds Acquisition"). These property
interests are primarily located in the Gulf Coast region and have combined
proved reserves of 33.0 Bcfe. Furthermore, these interests include 18,209 net
undeveloped leasehold acres with 3-D seismic-based exploration potential. The
Company will acquire these property interests at an aggregate cost of $30.0
million, effective January 1, 1997, for a unit cost of $0.65 per Mcfe of net
proved reserves. The Funds Acquisition will provide the Company with a larger
interest in certain of its existing properties, including the West Delta 30
Field in the Gulf of Mexico.

THE MICHIGAN DISPOSITION. The Company recently sold its interests in a
natural gas development project located in northwestern Michigan (the "Michigan
Development Project"). The Company views this transaction (the "Michigan
Disposition") as a disposition of non-core assets and a further enhancement of
its focus on the Gulf Coast region. As a result of the Michigan Disposition, the
Company sold 28.8 Bcfe of proved reserves as of December 31, 1996 (of which 3.3
Bcfe were proved developed producing as of December 31, 1996) and interests in a
pipeline company and a processing company. See "Unaudited Condensed Pro Forma
Financial Statements" and the related notes thereto.

DEVELOPMENT, EXPLOITATION AND EXPLORATION PROJECTS

RABBIT ISLAND FIELD. In 1993 the Company purchased a 25% interest in the
Rabbit Island Field located in Louisiana state waters. The field has produced in
excess of 1.2 Tcf of gas and 46 MMBbls of oil. A 105 square-mile 3-D survey was
interpreted in 1993, and six of seven wells drilled since that time have been
successful, discovering 34.3 Bcfe of gross proved reserves (7.2 Bcfe net to the
Company's interest). The Company, Texaco Exploration and Production Inc.
("Texaco") and Shell Offshore Inc. ("Shell") are conducting a joint field study
to delineate additional exploitation opportunities in this field. This study is
expected to be completed in the third quarter of 1997. The preliminary results
of the study indicate at least 25 potential exploitation opportunities.

WEST DELTA 30. In 1995 the Company purchased a 70% working interest in the
West Delta 30 Field in the Gulf of Mexico from Shell and initiated an integrated
geological, geophysical and 3-D seismic study in the first half of 1996. As a
result of this study, the Company identified eight additional development
drilling locations and three deeper pool prospects that the Company believes
have significant exploratory potential. Based on the Company's proposal, Exxon
Company, U.S.A. ("Exxon"), the operator, is drilling a well to test this field's
deeper exploratory potential and is scheduled to drill a development well by
year-end 1997.

MATAGORDA ISLAND 519. In late 1994 the Company purchased 13 producing
fields in the Gulf of Mexico from Pennzoil Company ("Pennzoil") for $51.3
million (the "Pennzoil Acquisition"), including the Matagorda Island 519 Field.
The Company owns working interests of 15.8% and 25% in this field, which is
operated by Amoco Production Company ("Amoco"). Workover operations on two wells
in this field were completed in the first quarter of 1997, increasing gross
production by 10 MMcf per day. Workover operations to recomplete a third well
are in progress. The Company believes that significant development and
exploratory potential remains in the field. Amoco has purchased a 3-D seismic
survey to delineate these opportunities, in which the Company owns a 25% working
interest.

6
<PAGE>
HIGH ISLAND 110/111. The Company purchased its initial interest in this
Texaco-operated field as part of the Pennzoil Acquisition and currently holds a
17% working interest. The Company has identified several recompletion zones and
two proved undeveloped drilling locations in the field using 3-D seismic data to
reinterpret an internal field study. These wells are scheduled to be drilled in
1997.

WASSON FIELD. In June 1996 the Company acquired a 34.7% working interest in
the Cornell Unit in the Wasson Field in West Texas. Approximately 1.5 billion
Bbls of oil have been produced from the San Andres reservoir from which the
Cornell Unit produces. The field was initially waterflooded in 1965, and a CO2
flood was initiated in 1985 utilizing the water alternating-gas injection method
of enhanced oil recovery. Because the field has been restored to its original
pressure as the result of tertiary recovery activities, at year-end 1996 the
Company recommended the cessation of CO2 purchases for the next four to five
years. This recommendation was adopted by the unit working interest owners. As a
result, the Company expects to increase its annual cash flow from the field by
$1.9 million. The Company, working with unit operator Exxon, has identified up
to 30 infill drilling locations. Furthermore, pressure tests performed recently
in an adjoining unit indicate that the upper gas-bearing sands may be produced
separately from the oil reservoir. Exxon and the Company plan to test the
feasibility of producing these gas-bearing sands in 1997.

THE OFFERING

Common Stock offered by the Company
pursuant to the Offering.............. 6,000,000 shares
Common Stock to be sold concurrently
with the Offering to Fund VII......... 643,037(1)
Common Stock to be outstanding after
the Offering and the Concurrent
Sale.................................. 14,306,721 shares(2)
Use of proceeds......................... The net proceeds to the Company of
the Offering and the Concurrent Sale
are estimated to be approximately
$83.0 million ($94.3 million if the
Underwriters' over-allotment option
is exercised in full) and will be
used (i) to pay the purchase price of
the Funds Acquisition and (ii) to
repay $52.2 million of indebtedness
outstanding under the Company's
existing credit facilities, with the
balance to be used for general
working capital purposes. See "Use of
Proceeds."
New York Stock Exchange Symbol.......... DXD
- ------------

(1) See "Transactions With Management and First Reserve -- Acquisition of
Common Stock by Fund VII."

(2) Does not include 849,694 shares of Common Stock reserved for issuance
pursuant to outstanding options under the Amended and Restated 1996 Stock
Purchase and Option Plan for Key Employees of Domain Energy Corporation and
Affiliates (the "Stock Purchase and Option Plan"). See "Management -- Stock
Purchase and Option Plan" and " -- Stock Option Agreements."

7
<PAGE>
SUMMARY HISTORICAL AND PRO FORMA COMBINED AND CONSOLIDATED FINANCIAL DATA

The following summary historical financial data are derived from the
financial statements of the Company as of and for the periods presented. The
summary historical financial data for the three-month periods ended March 31,
1996 and 1997 are derived from financial statements that are unaudited but
include all adjustments, consisting of normal recurring adjustments, that the
Company considers necessary for a fair presentation of its financial position
and results of operations for these periods. The results for the three months
ended March 31, 1997 are not necessarily indicative of the results for the full
year. The summary unaudited pro forma data are derived from the Unaudited
Condensed Pro Forma Financial Statements of the Company included elsewhere in
this Prospectus. The unaudited pro forma income statement data and other
financial data for the year ended December 31, 1996 and the three months ended
March 31, 1997 give effect to (i) the Acquisition, (ii) the Michigan
Disposition, (iii) the completion of the Offering, (iv) the completion of the
Concurrent Sale and (v) the completion of the Funds Acquisition, as if all such
transactions occurred on January 1, 1996. The unaudited pro forma balance sheet
data as of March 31, 1997 give effect to (i) the purchase of Common Stock by the
Company's employees in April 1997, (ii) the Michigan Disposition, (iii) the
completion of the Offering, (iv) the completion of the Concurrent Sale and (v)
the completion of the Funds Acquisition as if all such transactions occurred on
March 31, 1997. The pro forma financial data are not necessarily indicative of
actual results of operations or financial position that would have occurred if
these transactions were completed on the indicated dates or of future results of
operations. The summary historical and pro forma financial data below should be
read in conjunction with "Capitalization," "Unaudited Condensed Pro Forma
Financial Statements," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the Combined and Consolidated
Financial Statements of the Company and the related notes thereto included
elsewhere in this Prospectus.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED
------------------------------------------- MARCH 31,
PREDECESSOR -------------------------------------
------------------------------- PRO FORMA PREDECESSOR SUCCESSOR PRO FORMA
1994 1995 1996 1996 1996 1997 1997
--------- --------- --------- --------- ----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and natural gas sales(1)........ $ 5,340 $ 34,877 $ 52,274 $70,746 $15,688 $12,782 $16,538
IPF Activities(2)................... 1,417 2,356 4,369 4,369 340 732 732
Other............................... 283 414 (413) 198 115 (292) 185
--------- --------- --------- --------- ----------- --------- ---------
Total revenues................. 7,040 37,647 56,230 75,313 16,143 13,222 17,455
--------- --------- --------- --------- ----------- --------- ---------
Expenses:
Lease operating..................... 1,790 7,980 10,207 14,438 2,127 3,060 4,078
Production and severance taxes...... 18 710 1,340 1,492 279 413 469
Depreciation, depletion and
amortization...................... 3,101 22,692 24,920 22,866 7,613 3,282 4,046
General and administrative, net..... 52 2,780 3,361 3,653 1,089 792 828
Corporate overhead allocation....... 944 2,627 4,827 4,827 939 -- --
Stock compensation.................. -- -- -- -- -- 3,150 3,150
--------- --------- --------- --------- ----------- --------- ---------
Total operating expenses....... 5,905 36,789 44,655 47,276 12,047 10,697 12,571
--------- --------- --------- --------- ----------- --------- ---------
Income from operations.................. 1,135 858 11,575 28,037 4,096 2,525 4,884
Interest expense, net................... -- -- 150 8,865 -- 1,109 (6)
--------- --------- --------- --------- ----------- --------- ---------
Income before income taxes.............. 1,135 858 11,425 19,172 4,096 1,416 4,890
Income tax provision.................... 735 351 4,394 7,338 1,342 1,735 3,054
--------- --------- --------- --------- ----------- --------- ---------
Net income (loss)....................... $ 400 $ 507 $ 7,031 $11,834 $ 2,754 $ (319) $ 1,836
========= ========= ========= ========= =========== ========= =========
Net income (loss) per share(3).......... $ 0.78 $ (0.03) $ 0.12
Common stock and common stock
equivalents outstanding............... 15,156 9,156 15,156

</TABLE>
(TABLE CONTINUED ON FOLLOWING PAGE)

8
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED
------------------------------------------- MARCH 31,
PREDECESSOR -------------------------------------
------------------------------- PRO FORMA PREDECESSOR SUCCESSOR PRO FORMA
1994 1995 1996 1996 1996 1997 1997
--------- --------- --------- --------- ----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
OTHER FINANCIAL DATA:
Operating income.................... $ 1,135 $ 858 $ 11,575 $28,037 $ 4,096 $ 2,525 $ 4,884
Net cash provided by operating
activities........................ 11,487 19,933 34,553 -- 5,715 8,112 --
Net cash used in investing
activities........................ (86,669) (39,728) (47,329) -- (10,634) (7,577) --
Net cash provided by financing
activities........................ 85,014 8,328 12,776 -- 5,285 5,511 --
Capital expenditures(4)............. 85,205 49,904 28,145 58,145 4,848 2,276 32,276
OTHER NON-GAAP FINANCIAL DATA:
EBITDA(5)........................... 4,236 23,550 36,495 50,903 11,709 8,957 12,080
IPF Program return of capital(6).... 3,507 2,638 4,618 4,618 517 3,426 3,426
EBITDA plus IPF Program return of
capital........................... 7,743 26,188 41,113 55,521 12,226 12,383 15,506
</TABLE>
AS OF MARCH 31, 1997
----------------------------
HISTORICAL PRO FORMA
----------- ----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Cash and cash equivalents........... $ 6,082 $ 8,711
Property, plant and equipment,
net................................ 63,636 93,636
IPF Program notes receivable........ 27,530 27,530
Total assets........................ 125,664 148,064
Long-term debt (including current
maturities)........................ 83,838 24,508
Stockholders' equity................ 32,493 114,904
- ------------

(1) Oil and natural gas sales increased from $5.3 million in 1994 to $52.3
million in 1996 primarily as a result of the Company's acquisition of
producing properties in 1994 and 1995, results of drilling activities in
1994, 1995 and 1996, and an increase in the net realized price of gas in
1996 relative to 1994 and 1995.

(2) IPF Activities includes income from the Company's IPF Program and the
Company's "GasFund" partnership with a financial investor. See "Business
and Properties -- Producer Investment Activities."

(3) Net income per share on a pro forma basis has been computed based on the net
income shown above and assuming that the 7,177,681 shares of Common Stock
purchased in connection with the Acquisition, the 486,003 shares of Common
Stock purchased by the Company's employees in 1997, the 849,694 shares of
Common Stock reserved for issuance pursuant to outstanding options under the
Stock Purchase and Option Plan, the 6,000,000 shares of Common Stock to be
issued pursuant to the Offering and the 643,037 shares of Common Stock to be
issued to Fund VII concurrently with consummation of the Offering have been
outstanding since January 1, 1996.

(4) Pro forma capital expenditures data excludes the Acquisition.

(5) EBITDA represents earnings before stock compensation expense, interest,
income taxes, depreciation, depletion and amortization. The Company believes
that EBITDA may provide additional information about the Company's ability
to meet its future requirements for debt service, capital expenditures and
working capital. EBITDA is a financial measure commonly used in the oil and
gas industry and should not be considered in isolation or as a substitute
for net income, operating income, net cash provided by operating activities
or any other measure of financial performance presented in accordance with
generally accepted accounting principles or as a measure of a company's
profitability or liquidity. Because EBITDA excludes some, but not all, items
that affect net income and may vary among companies, the EBITDA calculation
presented above may not be comparable to similarly titled measures of other
companies.

(6) To more accurately reflect the actual cash flow generated by the Company,
IPF Program return of capital is identified separately to allow such cash
receipts to be combined with EBITDA.
========================
Based on unaudited financial information available to the Company for the
period from April 1, 1997 to the date of this Prospectus, the Company estimates
that it will report net income (loss) on approximately a "break-even" basis for
the three-month period ended June 30, 1997.

9
<PAGE>
SUMMARY OIL AND NATURAL GAS RESERVE DATA

The following table summarizes the estimates of the Company's historical
and pro forma net proved oil and natural gas reserves as of the dates indicated
and the present value attributable to the reserves at such dates. The reserve
and present value data as of December 31, 1994, 1995 and 1996 have been prepared
by DeGolyer and MacNaughton and other third-party petroleum engineers. See
"Business and Properties -- Oil and Natural Gas Reserves." Summaries of the
December 31, 1996 reserve reports and the letters of the third-party petroleum
engineers with respect thereto are included as Appendix A to this Prospectus.
The operating and reserve data set forth below does not include the Company's
term overriding royalty interests and associated reserves acquired through the
IPF Program.

AS OF DECEMBER 31,
-------------------------------------------
PRO FORMA
1994 1995 1996(1) 1996(2)
------- -------- -------- --------
PROVED RESERVES:
Natural gas (MMcf) .......... 73,399 82,682 81,338 83,418
Oil and condensate (MBbls) .. 4,109 2,197 11,380 11,736
Total (MMcfe) ............... 98,056 95,865 149,616 153,834
PV-10 Reserve Value (in
thousands) ................ $61,812 $103,931 $184,816 $213,030
Percent of proved developed
producing reserves ........ 53.4% 55.0% 61.3% 66.5%
Reserve Life Index (in
years)(3) ................. -- 4.7x 6.0x 4.9x
RESERVE REPLACEMENT DATA:
Finding costs (per Mcfe) .... $ 0.91 $ 1.13 $ 0.51 $ 0.66
Production replacement
ratio(4) .................. 3,117.9% 222.8% 217.9% 276.8%
- ------------

(1) Includes the Company's proportionate share of reserves attributable to the
Michigan Development Project.

(2) Gives effect to the Michigan Disposition and the Funds Acquisition as if
such transactions were consummated as of January 1, 1996.

(3) Calculated by dividing year-end proved reserves by annual actual or pro
forma production (as applicable) for the most recent year. The Company's
Reserve Life Index for 1994 was 34.6 and is excluded from the above table
because it reflects the Company's completion of a large acquisition in late
1994 and does not reflect production attributable to that acquisition for a
full-year period.

(4) Equals current period reserve additions through acquisitions of reserves,
extensions and discoveries, and revisions to prior estimates divided by the
production for such period.

SUMMARY OPERATING DATA

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------ ------------------------------------
PRO FORMA PREDECESSOR SUCCESSOR PRO FORMA
1994 1995 1996 1996(1) 1996 1997 1997(1)
--------- --------- --------- --------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Natural gas (MMcf)............... 2,334 18,065 21,192 25,714 5,828 3,668 4,586
Oil and condensate (MBbls)....... 83 424 564 920 116 141 199
Total (MMcfe).................... 2,832 20,609 24,575 31,234 6,524 4,516 5,780
AVERAGE REALIZED PRICES:(2)
Natural gas (per Mcf)............ $ 1.76 $ 1.54 $ 1.97 $ 2.06 $ 2.36 $ 2.75 $ 2.74
Oil and condensate (per Bbl)..... 14.93 16.76 18.63 19.43 16.52 19.06 20.07
EXPENSES (PER MCFE):
Lease operating.................. $ 0.63 $ 0.39 $ 0.42 $ 0.46 $ 0.33 $ 0.68 $ 0.71
Production taxes................. 0.01 0.03 0.05 0.05 0.04 0.09 0.08
Depreciation, depletion and
amortization................... 1.03 1.08 1.01 0.71 1.19 0.69 0.70
General and administrative,
net(3)......................... 0.26 0.16 0.12 0.12 0.14 0.14 0.14
</TABLE>
- ------------

(1) Gives effect to the Michigan Disposition and the Funds Acquisition as if
such transactions were consummated as of January 1, 1996.

(2) Reflects the actual realized prices received by the Company, including the
results of the Company's hedging activities. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Other
Matters -- Hedging Activities."

(3) Includes production attributable to properties managed for the Funds for the
periods indicated and excludes fees received from investors and overhead
allocations from Tenneco. Including Tenneco allocations, average net general
and administrative expenses per Mcfe for the years ended December 31, 1994,
1995 and 1996 would be $0.26, $0.20 and $0.28, respectively.

10
<PAGE>
RISK FACTORS

THIS PROSPECTUS CONTAINS FORWARD-LOOKING STATEMENTS. THE WORDS
"ANTICIPATE," "BELIEVE," "EXPECT," "PLAN," "INTEND," "SEEK," "ESTIMATE,"
"PROJECT," "WILL," "COULD," "MAY" AND SIMILAR EXPRESSIONS ARE INTENDED TO
IDENTIFY FORWARD-LOOKING STATEMENTS. THESE STATEMENTS INCLUDE INFORMATION
REGARDING OIL AND GAS RESERVES, FUTURE ACQUISITIONS, FUTURE DRILLING AND
OPERATIONS, FUTURE CAPITAL EXPENDITURES, FUTURE PRODUCTION OF OIL AND GAS AND
FUTURE NET CASH FLOW. SUCH STATEMENTS REFLECT THE COMPANY'S CURRENT VIEWS WITH
RESPECT TO FUTURE EVENTS AND FINANCIAL PERFORMANCE AND INVOLVE RISKS AND
UNCERTAINTIES, INCLUDING WITHOUT LIMITATION, THE RISKS DESCRIBED UNDER THIS
CAPTION "RISK FACTORS." SHOULD ONE OR MORE OF THESE RISKS OR UNCERTAINTIES
OCCUR, OR SHOULD UNDERLYING ASSUMPTIONS PROVE INCORRECT, ACTUAL RESULTS MAY VARY
MATERIALLY AND ADVERSELY FROM THOSE ANTICIPATED, BELIEVED, ESTIMATED OR
OTHERWISE INDICATED. CONSEQUENTLY, ALL OF THE FORWARD-LOOKING STATEMENTS MADE IN
THIS PROSPECTUS ARE QUALIFIED BY THESE CAUTIONARY STATEMENTS AND THERE CAN BE NO
ASSURANCE THAT THE ACTUAL RESULTS OR DEVELOPMENTS ANTICIPATED BY THE COMPANY
WILL BE REALIZED OR, EVEN IF SUBSTANTIALLY REALIZED, THAT THEY WILL HAVE THE
EXPECTED CONSEQUENCES TO OR EFFECTS ON THE COMPANY OR ITS BUSINESS OR
OPERATIONS. THE FOLLOWING RISK FACTORS SHOULD BE CONSIDERED CAREFULLY IN
ADDITION TO THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS BEFORE PURCHASING
THE SHARES OF COMMON STOCK OFFERED HEREBY.

VOLATILITY OF OIL AND NATURAL GAS PRICES; MARKETABILITY OF PRODUCTION

The Company's financial condition, profitability, future rate of growth and
ability to borrow funds or obtain additional capital, as well as the carrying
value of its oil and natural gas properties, are substantially dependent upon
prevailing prices of, and demand for, oil and natural gas. The energy markets
have historically been, and are likely to continue to be, volatile, and prices
for oil and natural gas are subject to large fluctuations in response to
relatively minor changes in the supply and demand for oil and natural gas,
market uncertainty and a variety of additional factors beyond the control of the
Company. These factors include the level of consumer product demand, weather
conditions, the actions of the Organization of Petroleum Exporting Countries,
domestic and foreign governmental regulations, political stability in the Middle
East and other petroleum producing areas, the foreign and domestic supply of oil
and natural gas, the price of foreign imports, the price and availability of
alternative fuels and overall economic conditions. A substantial or extended
decline in oil or natural gas prices could have a material adverse effect on the
Company's financial position, results of operations, quantities of oil and
natural gas reserves that may be economically produced, carrying value of its
proved reserves, borrowing capacity and access to capital. In addition, the
marketability of the Company's production depends upon a number of factors
beyond the Company's control, including the availability and capacity of
transportation and processing facilities, the effect of federal and state
regulation of oil and natural gas production and transportation, changes in
supply due to drilling by other producers and changes in demand. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."

RISK OF HEDGING ACTIVITIES

The Company's use of energy swap arrangements to reduce its sensitivity to
oil and natural gas price volatility is subject to a number of risks. If the
Company's reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, or otherwise, the Company would be required to satisfy
its obligations under potentially unfavorable terms. If the Company enters into
financial instrument contracts for the purpose of hedging prices and the
estimated production volumes are less than the amount covered by these
contracts, the Company would be required to mark-to-market these contracts and
recognize any and all losses within the determination period. Further, under
financial instrument contracts the Company may be at risk for basis
differential, which is the difference in the quoted financial price for contract
settlement and the actual physical point of delivery price. The Company will
from time to time attempt to mitigate basis differential risk by entering into
basis swap contracts. Substantial variations between the assumptions and
estimates used by the Company in its hedging activities and actual results
experienced could materially adversely affect the Company's anticipated profit
margins and its ability to manage risk associated with fluctuations in

11
<PAGE>
oil and natural gas prices. Furthermore, the fixed price sales and hedging
contracts limit the benefits the Company will realize if actual prices rise
above the contract prices.

As of March 31, 1997, on a pro forma basis, approximately 34.6% of the
Company's projected 1997 oil production and approximately 45.3% of its projected
1997 natural gas production were committed to hedging contracts. In addition,
the Company has hedges in place covering a portion of its projected oil
production through the year 2000. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Other Matters -- Hedging
Activities."

RESERVE REPLACEMENT RISKS

The Company's future performance is dependent upon its ability to identify,
acquire and develop additional oil and natural gas reserves that are
economically recoverable. Without successful drilling or acquisition activities,
the Company's reserves and revenues will decline. No assurances can be given
that the Company will be able to identify, acquire or develop additional
reserves at an acceptable cost.

The successful acquisition of producing properties requires an assessment
of recoverable reserves, future oil and natural gas prices, operating costs,
potential environmental and other liabilities and other factors beyond the
Company's control. This assessment is necessarily inexact and its accuracy is
inherently uncertain. In connection with such an assessment, the Company
typically performs, or retains a third party to perform, a review of the subject
properties, which review the Company believes is generally consistent with
industry practices. This review, however, will not reveal all existing or
potential problems, nor will it permit the Company to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not be performed on every well, and structural and
environmental problems are not necessarily observable even when an inspection is
undertaken. The Company generally assumes preclosing liabilities, including
environmental liabilities, in connection with property acquisitions and
generally acquires interests in the properties on an "as is" basis. With respect
to its acquisitions to date, the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. There can be no
assurance that any properties acquired by the Company will be successfully
developed or produced, and any such properties that are not successfully
developed or produced could have a material adverse effect on the Company.

Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that any new wells drilled by the Company will be productive or that
the Company will recover all or any portion of its investment. Drilling for oil
and natural gas may involve unprofitable efforts, not only from dry wells, but
from wells that are productive but do not produce sufficient net revenues to
return a profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. In addition, the Company's
use of 3-D seismic requires greater pre-drilling expenditures than traditional
drilling strategies. The Company's drilling operations may be curtailed, delayed
or canceled as a result of numerous factors, many of which are beyond the
Company's control, including economic conditions, mechanical problems, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment and services. There can be no
assurances that any of the Company's future drilling activities will be
successful, and unsuccessful drilling activities by the Company may have a
material adverse effect on the Company. See "Business and Properties --
Operating Hazards and Drilling Risks."

NON-OPERATOR STATUS

With the exception of the Mustang Island 846/847 Field and the Company's
interests in Michigan, all of the Company's oil and gas properties are operated
by others. As a result, the Company has a limited ability to exercise control
over operations or the associated costs of such operations. The success of the
Company's investment in a drilling or acquisition activity is therefore
dependent upon a number of factors that are outside of the Company's control,
including the competence and financial resources of the operator. Such factors
include the availability of future capital resources of the other participants
for the drilling of wells and the approval of other participants of the drilling
of wells on the properties in which the Company has an interest. The Company's
reliance on the operator and other working interest owners and its limited

12
<PAGE>
ability to control certain costs could have a material adverse effect on the
realization of expected rates of return on the Company's investment in drilling
or acquisition activities.

OPERATING RISKS

The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases. Any of these occurrences could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Moreover, offshore operations are
subject to a variety of operating risks peculiar to the marine environment,
including hurricanes or other adverse weather conditions, more extensive
governmental regulation (including regulations that may, in certain
circumstances, impose strict liability for pollution damage) and interruption or
termination of operations by governmental authorities based on environmental or
other considerations. The presence of unanticipated pressure or irregularities
in formations, miscalculations or accidents may cause a drilling or production
operation to be unsuccessful, resulting in a total loss of the Company's
investment in such operation. Although the Company maintains insurance coverage
it believes is customary in the industry for companies of similar size, it is
not fully insured against certain of these risks, either because such insurance
is not available or because of the high premium costs. The Company does not
carry business interruption insurance. There can be no assurance that any
insurance obtained by the Company will be adequate to cover any losses or
liabilities, or that such insurance will continue to be available or available
on terms that are acceptable to the Company. See "Business and Properties --
Operating Hazards and Drilling Risks."

RELIANCE ON ESTIMATES OF OIL AND NATURAL GAS RESERVES

The reserve data set forth in this Prospectus represent only estimates of
DeGolyer and MacNaughton ("DeGolyer"), Netherland, Sewell & Associates, Inc.
("Netherland, Sewell"), and other third-party petroleum engineers. The
estimation of reserve data is a subjective process of estimating the recovery of
underground accumulations of oil and natural gas that cannot be measured in an
exact manner, and the accuracy of any reserve estimate is a function of the
quality of the available data, the assumptions made, and engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows therefrom necessarily
depend upon a number of variable factors and assumptions, including historical
production from the area compared with production from other producing areas,
the assumed effects of regulation by governmental agencies and assumptions
concerning future oil and natural gas prices, future operating costs, severance
and excise taxes, development costs and workover and remedial costs, all of
which may in fact vary considerably from actual results. Any such estimates are
therefore inherently imprecise, and estimates by other engineers, or by the same
engineers at a different time, might differ materially from those included
herein. Actual prices, production, development expenditures, operating expenses
and quantities of recoverable oil and natural gas reserves will vary from those
assumed in the estimates, and it is likely that such variances will be
significant. Any significant variance from the assumptions could result in the
actual quantity of the Company's reserves and future net cash flows therefrom
being materially different from the estimates set forth in this Prospectus. In
addition, the Company's estimated reserves may be subject to downward or upward
revision, based upon production history, results of future exploration and
development, prevailing oil and natural gas prices, operating and development
costs and other factors. The Company's properties may also be susceptible to
hydrocarbon drainage from production by other operators on adjacent properties.
See "Business and Properties -- Oil and Natural Gas Reserves."

The present value of future net cash flows set forth in this Prospectus
should not be construed as the current market value or the value at any prior
date of the estimated oil and natural gas reserves attributable to the Company's
properties. In accordance with applicable requirements of the Securities and
Exchange Commission (the "Commission"), the estimated discounted future net cash
flows from estimated proved reserves are based on prices and costs as of the
date of the estimate unless such prices or costs are

13
<PAGE>
contractually determined at such date. Actual future prices and costs may be
materially higher or lower. Actual future net cash flows also will be affected
by factors such as actual production, supply and demand for oil and natural gas,
curtailments or increases in consumption by natural gas purchasers, changes in
governmental regulations or taxation and the impact of inflation on costs. In
addition, the 10% discount factor used to calculate the present value of future
net cash flows is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with the Company
or the oil and gas industry in general.

CERTAIN RISKS AFFECTING THE COMPANY'S IPF PROGRAM

The Company's IPF Program involves an up-front cash payment for the
purchase of a term overriding royalty interest pursuant to which the Company
receives an agreed upon share of revenues from identified properties. The
producer's obligation to deliver such revenues is nonrecourse to the producer
insofar as the producer generally is not liable to the Company for any failure
to meet its payment obligation except for such failures attributable to the
producer's failure to operate prudently, title failure or certain other causes
within the control of the producer. Consequently, the Company's ability to
realize successful investments through its producer finance business is subject
to the Company's ability to estimate accurately the volumes of recoverable
reserves from which the applicable production payment is to be discharged and
the operator's ability to recover these reserves. The Company's interest is
believed to constitute a property interest and, therefore, in the event of the
producer's bankruptcy or similar event, outside of the reach of the producer's
creditors; however, such creditor (or the producer as debtor-in-possession or a
trustee for the producer in a bankruptcy proceeding) may argue that the
transaction should be characterized as a loan, in which case the Company may
have only a creditor's claim for repayment of the amounts advanced. As
non-operating interests, the Company's ownership of these production payments
should not expose the Company to liability attendant to the ownership of direct
working interests, such as environmental liabilities and liabilities for
personal injury or death or damage to the property of others, although no
assurances can be made in this regard. Finally, as the producer's obligation is
only to deliver a specified share of revenues, subject to the ability of the
burdened reserves to produce such revenues, the Company bears the risk that
future revenues delivered will be insufficient to amortize the purchase price
paid by the Company for the interest or to provide any investment return
thereon.

The Company operates the IPF Program through its indirect wholly-owned
subsidiary, Domain Energy Finance Corporation ("IPF Company"). IPF Company has a
$100.0 million revolving credit facility with a bank (the "IPF Company Credit
Facility") pursuant to which it finances a portion of the IPF Program. The
borrowing base under the facility as of May 7, 1997 was $23.0 million. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- IPF Company Credit Facility."

EFFECTS OF LEVERAGE

On a pro forma basis as of March 31, 1997, the Company would have had total
consolidated indebtedness for money borrowed of approximately $24.5 million
(consisting of approximately $12.2 million outstanding under the Company's
revolving credit facility with a group of banks (the "Revolving Credit
Facility") and approximately $12.3 million outstanding under the IPF Company
Credit Facility) and stockholders' equity of approximately $114.9 million. The
Company intends to incur additional indebtedness for money borrowed in the
future, including in connection with the exploration for, and development,
production and acquisition of, oil and natural gas properties. These activities
could cause the Company's leverage to increase, which could have important
consequences to its stockholders, including the following: (i) the Company's
ability to obtain additional financing for working capital, capital
expenditures, acquisitions or general corporate purposes could be impaired in
the future; (ii) a substantial portion of the Company's cash flow from
operations could be required for the payment of principal and interest on its
indebtedness for money borrowed, thereby reducing the funds available to the
Company for its operations and other purposes; (iii) the Company may be
substantially more leveraged than certain of its competitors, which could place
the Company at a competitive disadvantage; and (iv) the Company's substantial
degree

14
<PAGE>
of leverage could hinder its ability to adjust rapidly to changing market
conditions and could make it more vulnerable in the event of a downturn in
general economic conditions or its business. In addition, the Company's
borrowings are and are expected to continue to be at variable rates, which
exposes the Company to the risk of increased interest rates. See " --
Substantial Capital Requirements" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital Resources
- -- Revolving Credit Facility."

The Company's ability to make scheduled payments of principal of and to pay
interest on, or to refinance, its indebtedness for money borrowed depends upon
its future performance and successful strategy implementation, which is subject
not only to its own actions but also to general economic, financial,
competitive, legislative, regulatory and other factors beyond its control, as
well as to the prevailing market prices for oil and natural gas. There can be no
assurance that the Company's business will generate sufficient cash flow from
operations or that future credit will be available in an amount sufficient to
enable the Company to service its indebtedness for money borrowed, or make
necessary capital expenditures. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

RESTRICTIVE DEBT COVENANTS

The Revolving Credit Facility contains covenants that, among other things,
restrict the ability of the Company to dispose of assets, incur additional
indebtedness or grant liens on its properties, repay other indebtedness, pay
dividends, enter into certain investments or acquisitions, repurchase or redeem
capital stock, engage in mergers or consolidations, or engage in certain
transactions with subsidiaries and affiliates and that will otherwise restrict
corporate activities. There can be no assurance that such restrictions will not
adversely affect the Company's ability to finance its future operations or
capital needs or engage in other business activities that may be in the
interests of the Company. In addition, the Revolving Credit Facility requires
the Company to maintain a specified minimum tangible net worth and to comply
with certain prescribed financial ratios. The ability of the Company to maintain
such tangible net worth or to comply with such ratios may be affected by events
beyond the Company's control. A breach of any of these covenants or the
inability of the Company to maintain such tangible net worth or to comply with
the required financial ratios could result in a default under the Revolving
Credit Facility. The Company believes that the Company is currently in
compliance with the terms of the Revolving Credit Facility. However, in the
event of any such default, the lenders thereunder (the "Lenders") could elect to
terminate the Company's ability to borrow thereunder, to declare all borrowings
outstanding thereunder, together with accrued interest and other fees, to be
immediately due and payable, and to exercise foreclosure or other remedies
against the Company and its assets. The Revolving Credit Facility is secured by
approximately 80% of the aggregate value of the Company's oil and natural gas
properties and substantially all of the Company's other property (other than the
IPF Program properties), including the capital stock of the Company's operating
subsidiaries. Although the remaining approximately 20% of the aggregate value of
the Company's oil and natural gas properties is not mortgaged to the Lenders
under the Revolving Credit Facility, such properties are nevertheless subject to
the restrictions set forth therein, including a prohibition on granting any
security interests therein. If the indebtedness under the Revolving Credit
Facility were to be accelerated, there can be no assurance that the assets of
the Company would be sufficient to repay such indebtedness in full. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Revolving Credit Facility."

The IPF Company Credit Facility restricts the ability of the IPF Company to
dividend cash to its parent, Domain Energy Ventures Corporation, or otherwise
advance cash to the Company. Consequently, cash generated by the IPF Company may
not be available to the Company, whether for repayment of the Revolving Credit
Facility or for other purposes. The IPF Company Credit Facility is secured by
substantially all of IPF Company's oil and gas interests, including the notes
receivable generated therefrom. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital Resources
- -- IPF Company Credit Facility."

15
<PAGE>
SUBSTANTIAL CAPITAL REQUIREMENTS

Historically, the Company has financed its activities primarily with
internally generated funds and advances from Tenneco. The Company currently has
plans for substantial capital expenditures to continue its exploration,
development, production and acquisition activities. In 1997, excluding
acquisitions, the Company's budget for capital expenditures and IPF Program
investments is $65.0 million. The Company's business plan is dependent upon the
Company's ability to obtain financing beyond its internally generated cash flow,
for exploring for, developing, producing and acquiring oil and natural gas
properties. Management believes that the Company will have sufficient cash
provided by operating activities and borrowings under the Revolving Credit
Facility to fund planned capital expenditures in 1997. The Revolving Credit
Facility limits the amounts the Company may borrow thereunder to amounts
determined by the Lenders in their sole discretion, based upon the Lenders'
projection of the Company's discounted future net revenues from oil and natural
gas properties and other considerations, and restricts the amounts the Company
may borrow under other credit facilities. The Lenders may periodically adjust
the borrowing base under the Revolving Credit Facility and may require that
outstanding borrowings in excess of the borrowing base be repaid within 30 days
of the date such excess occurs. All amounts owed under the Revolving Credit
Facility are due and payable on December 31, 1999. In addition, the borrowing
base under the Revolving Credit Facility is scheduled to be redetermined as of
December 31, 1997 and may be reduced substantially from its March 31, 1997 level
of $63.3 million. All amounts outstanding in excess of such reduced borrowing
base must be paid in full at such date. If revenues or the Company's borrowing
base decrease as a result of lower oil and natural gas prices, operating
difficulties, declines in reserves or otherwise, the Company's ability to expend
the capital necessary to undertake or complete future activities may be
significantly limited. No assurances can be given that the Company will have
adequate funds available to it under the Revolving Credit Facility to carry out
its strategy or that the Company will be able to make any mandatory principal
payments required by the Lenders. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and " -- Revolving Credit Facility."

CONTROL BY EXISTING STOCKHOLDERS AND POTENTIAL CONFLICTS OF INTEREST

Upon completion of the Offering and the Concurrent Sale, the Company's
existing stockholders will own approximately 58.1% of the outstanding shares of
Common Stock (approximately 54.6% if the Underwriter's over-allotment option is
exercised in full). First Reserve Fund VII, Limited Partnership, a Delaware
limited partnership ("Fund VII"), the managing general partner of which is First
Reserve Corporation, a Delaware corporation ("First Reserve"), individually will
own approximately 54.7% of the outstanding shares of Common Stock (approximately
51.4% if the Underwriter's over-allotment option is exercised in full). As a
result of such stock ownership, the Company's existing stockholders, as a group,
and Fund VII, individually, will be able to elect all members of the Company's
board of directors (the "Board of Directors") and to control the vote on matters
submitted to the Board of Directors or stockholders, including, without
limitation, matters relating to the Company's exploration, development, capital,
operating and acquisition expenditure plans, as well as mergers and other
business combinations, asset sales, financings, issuances of securities and
other significant transactions.

Such concentration of ownership of Common Stock may have an adverse effect
on the market price of the Common Stock. Conflicts of interest may arise in the
future between the Company and First Reserve and its affiliates with respect to,
among other things, potential competitive business activities or business
opportunities, issuances of additional shares of voting securities, the election
of directors or the payment of dividends, if any, by the Company or the exercise
by First Reserve, as managing general partner of Fund VII, of its ability to
control the management and affairs of the Company. There are no contractual or
other restrictions on the ability of First Reserve or its affiliates to engage
in oil and gas exploration and production or to pursue other investment
opportunities in the energy industry. Circumstances could arise in the future in
which the Company and First Reserve or its affiliates engage in activities in
competition with one another.

16
<PAGE>
DEPENDENCE ON KEY PERSONNEL

The Company's operations are dependent upon a relatively small group of
management and technical personnel. The loss of one or more of these individuals
could have a material adverse effect on the Company. The Company in particular
is substantially dependent on the efforts of Michael V. Ronca, its President and
Chief Executive Officer. If Mr. Ronca becomes unable or unwilling to continue in
his present role, the Company's business, operations and prospects would be
adversely affected. In connection with the consummation of the acquisition by
the Company of the capital stock of its operating subsidiaries, Mr. Ronca
entered into an Employment Agreement with the Company (the "Ronca Employment
Agreement"). Under the terms of the Ronca Employment Agreement, Mr. Ronca would
be entitled to terminate his employment (i) upon a "Change of Control," which is
defined therein as the acquisition by any person or entity, or group thereof,
excluding Fund VII and other affiliates of First Reserve, of more than 50% of
the outstanding voting stock of the Company, or (ii) otherwise for "Good
Reason," which is defined therein to include, among other things, material
reductions in Mr. Ronca's duties, responsibilities or base salary. See
"Management -- Ronca Employment Agreement." The Company does not maintain key
person life insurance for Mr. Ronca or any of its other personnel.

COMPETITION

The Company encounters competition from other companies in all areas of its
operations, including the acquisition of producing properties and its IPF
Program. The Company's competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals
and drilling and income programs and, in the case of its IPF Program, affiliates
of investment, commercial and merchant banking firms and affiliates of large
interstate pipeline companies. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Company and which, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Company. Such companies may be able to pay more for producing oil and natural
gas properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future, as well as its ability to
grow its IPF Program, will be dependent upon its ability to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment.

GOVERNMENTAL REGULATION AND ENVIRONMENTAL MATTERS

Oil and natural gas operations are subject to various federal, state and
local governmental laws and regulations that may be changed from time to time in
response to economic, political or other conditions. Matters subject to
regulation include discharge permits for drilling operations, drilling and
abandonment bonds, reports concerning operations, the spacing of wells,
unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and natural gas wells below actual
production capacity in order to conserve supplies of such resources. In
addition, the production, handling, storage, transportation and disposal of oil
and natural gas, by-products thereof and other substances and materials produced
or used in connection with oil and natural gas operations are subject to
regulation under federal, state and local laws and regulations primarily
relating to protection of human health and the environment. These laws and
regulations have imposed increasingly strict requirements for water and air
pollution control and solid waste management. To date, the Company's
expenditures related to compliance with these laws and regulations have not been
significant, although no assurances can be given that such expenditures will not
be significant in the future. The Company believes that the trend of more
expansive and stricter environmental legislation and regulations, including
regulations that may be promulgated under the Oil Pollution Act of 1990, will
continue, and that such legislation and regulations may result in additional
costs to the Company in the future. Amendments to the Resource Conservation and
Recovery Act to regulate further the handling, transportation, storage and
disposal of oil and natural gas exploration and production wastes have been

17
<PAGE>
considered by Congress and may be adopted. Such legislation, if enacted, could
have a material adverse impact on the Company's operating costs. See "Business
and Properties -- Regulation."

NO PRIOR PUBLIC MARKET; POSSIBLE VOLATILITY OF STOCK PRICE; DILUTION

Prior to the Offering, there has been no public market for the Common
Stock. The initial public offering price will be determined by negotiations
among the Company, First Reserve and the Underwriters and may not be indicative
of the future market price for the Common Stock. See "Underwriting" for a
discussion of the factors to be considered in determining the initial public
offering price. The Common Stock has been approved for listing on the New York
Stock Exchange, subject to notice of issuance. However, no assurance can be made
that an active trading market for the Common Stock will develop or, if
developed, that it will be sustained. The market price of the Common Stock could
also be subject to significant fluctuation in response to variations in results
of operations and other factors. In addition, Fund VII and certain employees of
the Company acquired their shares of Common Stock (other than the Common Stock
to be purchased by Fund VII pursuant to the Concurrent Sale) at a per share
price that is substantially less than the initial public offering price.
Investors in the Common Stock offered hereby will experience immediate and
substantial dilution in the net tangible book value of their shares of Common
Stock. At an initial public offering price of $13.50 per share, the dilution to
new investors will be $5.47 per share. These investors will also experience
additional dilution upon the exercise of outstanding options for the Common
Stock. See "Dilution."

SHARES ELIGIBLE FOR FUTURE SALE

The Company, each of the Company's directors and executive officers and
Fund VII have agreed not to dispose of any shares of Common Stock without the
prior consent of Credit Suisse First Boston Corporation for a period of 180 days
from the date of this Prospectus other than pursuant to the Offering or in
connection with the Company's employee benefit plans. The shares of Common Stock
held by the Company's officers and by Fund VII are deemed "restricted
securities" within the meaning of Rule 144 under the Securities Act of 1933, as
amended (the "Securities Act"), and may be resold after the 180-day period only
upon registration under the Securities Act or pursuant to an exemption from
registration, including exemptions contained in Rule 144. Pursuant to the terms
of the Securityholders Agreement, dated as of December 31, 1996, among the
Company, Fund VII and the Company's officers who have subscribed for Common
Stock, upon the consummation of the Offering and after expiration of the 180-day
period referred to above, Fund VII will have the right to demand registration of
its shares of Common Stock. See "Transactions With Management and First Reserve
- -- Securityholders Agreement." Fund VII has informed the Company that it has no
immediate plans to sell or otherwise dispose of shares of the Common Stock. As
of the date hereof, options exercisable for 849,694 shares of Common Stock are
outstanding under the Amended and Restated 1996 Stock Purchase and Option Plan
for Key Employees of Domain Energy Corporation and Affiliates (the "Stock
Purchase and Option Plan"). Generally, all shares issued upon the exercise of
such options will be freely tradeable under the Securities Act. Sales of
substantial amounts of Common Stock in the public market, or the perception of
the availability of shares for sale, following the Offering could adversely
affect the prevailing market price of the Common Stock. The Company is unable to
make any prediction as to the effect, if any, that the future sales of Common
Stock or the availability of Common Stock for sale will have on the market price
of the Common Stock prevailing from time to time. See "Shares Eligible for
Future Sale."

BLANK CHECK PREFERRED STOCK

The Company's Amended and Restated Certificate of Incorporation (the
"Certificate of Incorporation") authorizes "blank check" preferred stock,
which may have the effect of discouraging unsolicited acquisition proposals. See
"Description of Capital Stock -- Preferred Stock."

18
<PAGE>
USE OF PROCEEDS

The net proceeds to the Company of the Offering and the Concurrent Sale are
estimated to be approximately $83.0 million ($94.3 million if the Underwriters'
over-allotment option is exercised in full), after deducting underwriting
discounts and commissions and estimated Offering expenses. The Company will use
approximately $30.0 million of the net proceeds to consummate the Funds
Acquisition. The Company will use $52.2 million of the proceeds to the Company
of the Offering and the Concurrent Sale to repay $47.2 million of indebtedness
outstanding under the Revolving Credit Facility and $5.0 million of indebtedness
outstanding under the IPF Company Credit Facility. The remainder of the net
proceeds will be used for general working capital purposes of the Company.
Pending application of the net proceeds of the Offering, such net proceeds will
be invested in short-term, interest bearing instruments.

In December 1996, the Company entered into the Revolving Credit Facility
under which the borrowing base was $63.3 million as of March 31, 1997. At such
date, borrowings outstanding under the Revolving Credit Facility totalled $59.5
million. The initial borrowings under the Revolving Credit Facility were used to
finance a portion of the costs of the Acquisition. The Revolving Credit Facility
is a three-year revolving credit facility with the entire outstanding principal
amount maturing on December 31, 1999. In addition, the borrowing base under the
Revolving Credit Facility may be redetermined by the Lenders at any time and is
scheduled to be redetermined as of December 31, 1997. Following any such
redetermination, the borrowing base may be reduced substantially from its then
current level. All amounts outstanding in excess of such reduced borrowing base
must be paid in full at such date. Absent a default or an event of default (as
defined therein), outstanding borrowings under the Revolving Credit Facility
accrue interest at LIBOR plus a margin of 1.50% to 2.50% per annum depending on
the total amount drawn or, at the option of the Company, at the greater of (i)
the prime rate and (ii) the federal funds effective rate plus one-half of 1%,
plus a margin of 0.50% to 1.50% depending on the total amount drawn. As of March
31, 1997, the weighted average interest rate applicable to outstanding
borrowings under the Revolving Credit Facility was 8.05% per annum. For a
description of the Revolving Credit Facility, including certain mandatory
prepayment terms, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources --
Revolving Credit Facility."

IPF Company is a party to the IPF Company Credit Facility, which provides
for a maximum $100.0 million revolving line of credit. Borrowings under this
facility are used to finance IPF Company's investment activities under the IPF
Program. The IPF Company Credit Facility matures June 1, 1999 at which time all
amounts owed thereunder are due and payable. The borrowing base under the
facility as of March 31, 1997 was $18.0 million and is subject to a scheduled
redetermination by the lender every six months and such other redeterminations
as the lender may elect to perform each year. Effective as of May 7, 1997, the
borrowing base under the facility was increased to $23.0 million. As of March
31, 1997, approximately $17.3 million was outstanding under the IPF Company
Credit Facility and the weighted average interest rate applicable to such
outstanding amount was 7.857% per annum. So long as no default or event of
default (as defined therein) is outstanding, borrowings under the IPF Company
Credit Facility accrue interest at LIBOR plus a margin of 2.25% or, at the
option of IPF Company, the prime rate published in THE WALL STREET JOURNAL. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- IPF Company Credit Facility."

DIVIDEND POLICY

The Company intends to retain its earnings to provide funds for
reinvestment in the Company's businesses, including exploration, development and
production activities, and, therefore, does not anticipate declaring or paying
cash dividends in the foreseeable future. The Company is a holding company that
conducts substantially all of its operations through its subsidiaries. As a
result, the Company's ability to pay dividends on the Common Stock would be
dependent on the cash flows of its subsidiaries. Payment of dividends is also
subject to then existing business conditions and the business results, cash
requirements and financial condition of the Company, and will be at the
discretion of the Board of Directors. In addition, the terms of the Revolving
Credit Facility currently prohibit the payment of dividends by the Company. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

19
<PAGE>
CAPITALIZATION

The following table sets forth (i) the capitalization of the Company as of
March 31, 1997 and (ii) the pro forma capitalization of the Company as of March
31, 1997 after giving effect to the purchase of Common Stock by the Company's
employees in April 1997, the Michigan Disposition, the issuance of 6,000,000
shares of Common Stock in this Offering and the application of the estimated net
proceeds therefrom as described under "Use of Proceeds" and the purchase by Fund
VII of 643,037 shares of Common Stock concurrently with consummation of the
Offering. This table should be read in conjunction with "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the Combined
and Consolidated Financial Statements of the Company and the related notes
thereto included elsewhere in this Prospectus.

MARCH 31, 1997
-------------------------
HISTORICAL PRO FORMA
---------- -----------
(IN THOUSANDS)
Current maturities of long-term debt.... 23,500 --
Long-term debt.......................... $ 60,338 $ 24,508
Stockholders' equity:
Preferred stock, $.01 par value, no
shares authorized and outstanding;
5,000,000 shares authorized and
none outstanding pro forma........ -- --
Common stock, $.01 par value,
15,080,000 shares authorized;
7,567,988 shares issued and outstanding;
25,000,000 shares authorized and
14,306,721 shares issued and outstanding
pro forma......................... 76 143
Additional paid-in capital......... 33,282 116,375
Notes receivable -- stockholders... (546) (546)
Retained earnings.................. (319) (1,068)
---------- -----------
Total stockholders' equity.............. 32,493 114,904
---------- -----------
Total capitalization.................... $ 116,331 $ 139,412
========== ===========

20
<PAGE>
DILUTION

"Dilution" means the difference between the initial public offering price
per share of Common Stock and the pro forma net tangible book value per share of
Common Stock after giving effect to the Offering. "Net tangible book value per
share" represents the amount of total tangible assets less total liabilities
divided by the total number of shares of Common Stock outstanding. At March 31,
1997, after giving effect to the purchase of Common Stock by the Company's
employees in April 1997, the Company's pro forma net tangible book value was
$32.9 million, or approximately $4.29 per share of Common Stock. Assuming the
sale of 6,000,000 shares pursuant to the Offering, the use of the net proceeds
thereof as specified in "Use of Proceeds" and the sale of 643,037 shares of
Common Stock at a price of $13.50 per share to Fund VII concurrently with
consummation of the Offering and the use of the proceeds thereof to repay
outstanding indebtedness under the Revolving Credit Facility, the pro forma net
tangible book value of the Company at March 31, 1997 would have been $8.03 per
share, representing an immediate increase in pro forma net tangible book value
of $3.74 per share to the Company's existing stockholders and an immediate
dilution in pro forma net tangible book value of $5.47 per share to new
investors purchasing shares of Common Stock in the Offering. The following table
illustrates such pro forma per share dilution at March 31, 1997:

Initial public offering price per share ........ $ 13.50
Pro forma net tangible book value per
share at March 31, 1997 .............. $ 4.29
Increase per share attributable to new
investors (including Fund VII) ....... 3.74
---------
Pro forma net tangible book value per
share after the Offering and the
Concurrent Sale ...................... 8.03
---------
Dilution per share to new investors ............ $ 5.47
=========

The following table sets forth the number of shares of Common Stock
purchased from the Company, the total consideration paid, and the average price
per share paid by existing stockholders and to be paid by Fund VII pursuant to
the Concurrent Sale and by purchasers of shares of Common Stock offered hereby
(before deducting underwriting discounts and commissions and estimated offering
expenses):

<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE
---------------------- ------------------------- PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
------------ ------- --------------- ------- ---------
<S> <C> <C> <C> <C> <C>
Existing stockholders.... 7,663,684 53.6% $32,031,354 26.3% $ 4.18
New investors (including
Fund VII).............. 6,643,037 46.4% 89,681,000 73.7% 13.50
------------ ------- --------------- -------
Total............... 14,306,721 100.0% $121,712,354 100.0%
============ ======= =============== =======
</TABLE>
The foregoing computations do not include 424,847 shares of Common Stock
issuable upon exercise of outstanding employee stock options at an exercise
price of $4.18 and 424,847 shares of Common Stock issuable upon exercise of
outstanding employee stock options at an exercise price of $.01 per share. See
"Management -- Stock Option Agreements."

21
<PAGE>
UNAUDITED CONDENSED PRO FORMA FINANCIAL STATEMENTS

On December 31, 1996, the Company completed the Acquisition pursuant to
which it acquired all of the outstanding capital stock of its operating
subsidiaries from El Paso Natural Gas Company for an aggregate purchase price of
approximately $96.2 million and the assumption of liabilities of approximately
$16.8 million. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- General." In April 1997 the Company completed the
Michigan Disposition pursuant to which it sold its interests in a natural gas
development project located in northwestern Michigan to Energy Acquisition
Corp., a Colorado corporation. See "Business and Properties -- Certain
Transactions -- The Michigan Disposition." Concurrently with the consummation of
the Offering, the Company expects to complete the Concurrent Sale pursuant to
which Fund VII will purchase 643,037 shares of Common Stock for an aggregate
purchase price of $8,681,000. See "Transactions with Management and First
Reserve -- Acquisition of Common Stock by Fund VII." Upon consummation of the
Offering, the Company expects to complete the Funds Acquisition pursuant to
which it will acquire certain net profits overriding royalty interests owned by
three institutional investors. The Company will acquire these interests for an
aggregate cost of $30.0 million. See "Business and Properties -- Certain
Transactions -- The Funds Acquisition."

The unaudited pro forma consolidated balance sheet as of March 31, 1997
gives effect to (i) the sale of 95,696 shares of Common Stock to the Company's
employees in April 1997 for an aggregate purchase price of $400,000, (ii) the
Michigan Disposition, (iii) the completion of the Offering, (iv) the completion
of the Concurrent Sale and (v) the completion of the Funds Acquisition, as if
all such transactions had occurred on March 31, 1997. The unaudited pro forma
consolidated income statements for the year ended December 31, 1996 and for the
three months ended March 31, 1997 give effect to (i) the Acquisition, (ii) the
Michigan Disposition, (iii) the completion of the Offering, (iv) the completion
of the Concurrent Sale and (v) the completion of the Funds Acquisition, as if
all such transactions (the "Transactions") had occurred on January 1, 1996. The
unaudited condensed pro forma balance sheet is based on the unaudited
Consolidated Balance Sheet of the Company included elsewhere in this Prospectus.
The unaudited condensed pro forma income statements are based on the historical
Combined Statements of Income of the Company and unaudited financial information
related to the Funds Acquisition.

The pro forma adjustments are based upon available information and certain
assumptions that management of the Company believes are reasonable. Management
of the Company does not believe that any possible deviations will be material to
the pro forma financial statements. The pro forma financial information does not
purport to represent what the Company's financial position or results of
operations would actually have been had the Transactions in fact occurred on
such dates. In addition, the pro forma financial statements are not necessarily
indicative of the results of future operations of the Company and should be read
in conjunction with "Capitalization," "Management's Discussion and Analysis of
Financial Condition and Results of Operations," and the Combined and
Consolidated Financial Statements of the Company and the related notes thereto
included elsewhere in this Prospectus.

22
<PAGE>
DOMAIN ENERGY CORPORATION
UNAUDITED CONDENSED PRO FORMA BALANCE SHEET
MARCH 31, 1997
<TABLE>
<CAPTION>
ADJUSTMENTS
FOR ADJUSTMENTS SUBTOTAL ADJUSTMENTS
EMPLOYEE FOR FOR ADJUSTMENTS FOR ADJUSTMENTS FOR
OFFERING IN MICHIGAN COMPLETED FOR CONCURRENT PENDING FUNDS
HISTORICAL APRIL 1997 DISPOSITION TRANSACTIONS OFFERING SALE ACQUISITION
---------- ----------- ----------- ------------ ----------- ----------- ---------------
(IN THOUSANDS, EXCEPT SHARE DATA)

ASSETS
<S> <C> <C> <C> <C> <C> <C> <C>
Cash and cash
equivalents............ $ 6,082 $ 400(a) $ 2,229 (b) $ 8,711 $ 30,000 (c) $-- $(30,000)(e)
Restricted certificate of
deposit................ 8,000 -- -- 8,000 -- (8,000)(d) --
Accounts receivable...... 13,989 -- (5,400)(b) 8,589 -- -- --
Notes receivable, current
portion................ 8,512 -- 5,400 (b) 13,912 -- -- --
Prepaids and other
current assets......... 1,468 -- -- 1,468 -- -- --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Total current
assets............. 38,051 400 2,229 $ 40,680 30,000 (8,000) (30,000)
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Notes receivable......... 19,018 -- -- 19,018 -- -- --
Property, plant and
equipment, net (full
cost method)........... 63,636 -- -- 63,636 -- -- 30,000 (e)
Investments, equity...... 2,229 -- (2,229)(b) -- -- -- --
Other assets............. 2,730 -- -- 2,730 -- -- --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Total assets......... $125,664 $ 400 $ -- 126,064 $ 30,000 $(8,000) $ --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
LIABILITIES AND
STOCKHOLDERS' EQUITY
Accounts payable......... $ 4,491 $ -- $ -- $ 4,491 $ -- $-- $ --
Accrued expenses......... 2,880 -- -- 2,880 -- (681)(d) --
Current maturities of
long-term debt......... 23,500 -- -- 23,500 (16,500)(c) (7,000)(d) --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Total current
liabilities........ 30,871 -- -- 30,871 (16,500) (7,681) --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Long-term debt........... 60,338 -- -- 60,338 (27,830)(c) (8,000)(d) --
Deferred taxes........... 1,550 -- -- 1,550 -- -- --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Total liabilities.... 92,759 -- -- 92,759 (44,330) (15,681) --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Minority interest........ 412 -- -- 412 -- -- --
Common stock
7,567,988 shares issued
and outstanding
historical; 14,306,721
shares issued and
outstanding pro
forma.................. 76 1(a) -- 77 60 (c) 6 (d) --
Additional paid-in
capital................ 33,282 1,148(a) -- 34,430 74,270 (c) 7,675 (d) --
Notes receivable --
shareholders........... (546) -- -- (546) -- -- --
Retained earnings........ (319) (749)(a) -- (1,068) -- -- --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Total stockholders'
equity............. 32,493 400 -- 32,893 74,330 7,681 --
---------- ----------- ----------- ------------ ----------- ----------- ---------------
Total liabilities and
stockholders'
equity............. $125,664 $ 400 $ -- $126,064 $ 30,000 $(8,000) $ --
========== =========== =========== ============ =========== =========== ===============
</TABLE>

PRO
FORMA
---------

ASSETS
Cash and cash
equivalents............ $ 8,711
Restricted certificate of
deposit................ --
Accounts receivable...... 8,589
Notes receivable, current
portion................ 13,912
Prepaids and other
current assets......... 1,468
---------
Total current
assets............. 32,680
---------
Notes receivable......... 19,018
Property, plant and
equipment, net (full
cost method)........... 93,636
Investments, equity...... --
Other assets............. 2,730
---------
Total assets......... $ 148,064
---------
LIABILITIES AND
STOCKHOLDERS' EQUITY
Accounts payable......... $ 4,491
Accrued expenses......... 2,199
Current maturities of
long-term debt......... --
---------
Total current
liabilities........ 6,690
---------
Long-term debt........... 24,508
Deferred taxes........... 1,550
---------
Total liabilities.... 32,748
---------
Minority interest........ 412
Common stock
7,567,988 shares issued
and outstanding
historical; 14,306,721
shares issued and
outstanding pro
forma.................. 143
Additional paid-in
capital................ 116,375
Notes receivable --
shareholders........... (546)
Retained earnings........ (1,068)
---------
Total stockholders'
equity............. 114,904
---------
Total liabilities and
stockholders'
equity............. $ 148,064
=========

The accompanying notes are an integral part of the pro forma financial
statements.

23
<PAGE>
DOMAIN ENERGY CORPORATION
UNAUDITED CONDENSED PRO FORMA INCOME STATEMENT
YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
ADJUSTMENTS ADJUSTMENTS
ADJUSTMENTS FOR SUBTOTAL FOR ADJUSTMENTS FOR
FOR THE MICHIGAN COMPLETED FOR CONCURRENT
HISTORICAL ACQUISITION DISPOSITION TRANSACTIONS OFFERING SALE
---------- ----------- ----------- ------------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

REVENUES
<S> <C> <C> <C> <C> <C> <C>
Oil and natural gas sales............... $ 52,274 $ -- $-- (j) $52,274 $-- $--
IPF Activities.......................... 4,369 -- -- 4,369 -- --
Other................................... (413) -- 605 (j) 192 -- --
---------- ----------- ----------- ------------- ----------- -----------
Total revenues..................... 56,230 -- 605 56,835 -- --
---------- ----------- ----------- ------------- ----------- -----------
EXPENSES
Lease operating......................... 10,207 -- -- 10,207 -- --
Production and severance taxes.......... 1,340 -- -- 1,340 -- --
Depreciation, depletion and
amortization.......................... 24,920 (8,520)(f) -- 16,400 -- --
General and administrative.............. 3,361 -- -- 3,361 -- --
Corporate overhead allocation........... 4,827 -- -- 4,827 -- --
---------- ----------- ----------- ------------- ----------- -----------
Total operating expenses........... 44,655 (8,520) -- 36,135 -- --
---------- ----------- ----------- ------------- ----------- -----------
Operating income........................ 11,575 (8,520) 605 20,700 -- --
---------- ----------- ----------- ------------- ----------- -----------
Interest expense, net................... 150 14,131 (g) -- 14,281 (3,765)(g) (976)(g)
Interest income......................... -- (368)(h) (675)(h) (1,043) -- 368 (k)
---------- ----------- ----------- ------------- ----------- -----------
Net income before income taxes.......... 11,425 (5,243) 1,280 7,462 3,765 608
Income tax expense...................... 4,394 (1,992)(i) 486 (i) 2,888 1,431 (i) 231 (i)
---------- ----------- ----------- ------------- ----------- -----------
Net income.............................. $ 7,031 $ (3,251) $ 794 $ 4,574 $ 2,334 $ 377
========== =========== =========== ============= =========== ===========
Net income per share....................
Common stock and common stock
equivalents outstanding...............
</TABLE>
ADJUSTMENTS
FOR
PENDING
FUNDS
ACQUISITION PRO FORMA
----------- ---------

REVENUES
Oil and natural gas sales............... $18,472(l) $70,746
IPF Activities.......................... -- 4,369
Other................................... 6(l) 198
----------- ---------
Total revenues..................... 18,478 75,313
----------- ---------
EXPENSES
Lease operating......................... 4,231(l) 14,438
Production and severance taxes.......... 152(l) 1,492
Depreciation, depletion and
amortization.......................... 6,466(l) 22,866
General and administrative.............. 292(l) 3,653
Corporate overhead allocation........... -- 4,827
----------- ---------
Total operating expenses........... 11,141 47,276
----------- ---------
Operating income........................ 7,337 28,037
----------- ---------
Interest expense, net................... -- 9,540
Interest income......................... -- (675)
----------- ---------
Net income before income taxes.......... 7,337 19,172
Income tax expense...................... 2,788(i) 7,338
----------- ---------
Net income.............................. $ 4,549 $11,834
=========== =========
Net income per share.................... $ 0.78
=========
Common stock and common stock
equivalents outstanding............... 15,156(m)
=========

The accompanying notes are an integral part of the pro forma financial
statements.

24
<PAGE>
DOMAIN ENERGY CORPORATION
UNAUDITED CONDENSED PRO FORMA INCOME STATEMENT
THREE MONTHS ENDED MARCH 31, 1997
<TABLE>
<CAPTION>
ADJUSTMENTS ADJUSTMENTS
ADJUSTMENTS FOR SUBTOTAL FOR ADJUSTMENTS FOR
FOR THE MICHIGAN COMPLETED FOR CONCURRENT
HISTORICAL ACQUISITION DISPOSITION TRANSACTIONS OFFERING SALE
---------- ----------- ------------ ------------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

REVENUES
<S> <C> <C> <C> <C> <C> <C>
Oil and natural gas..................... $ 12,782 $-- $-- $12,782 $ -- $ --
IPF Activities.......................... 732 -- -- 732 -- --
Other................................... (292) -- 477 (j) 185 -- --
---------- ----------- ------------ ------------- ----------- -----------
Total revenues..................... 13,222 -- 477 13,699 -- --
---------- ----------- ------------ ------------- ----------- -----------
EXPENSES
Lease operating......................... 3,060 -- -- 3,060 -- --
Production and severance taxes.......... 413 -- -- 413 -- --
Depreciation, depletion and
amortization.......................... 3,282 (534)(f) -- 2,748 -- --
General and administrative.............. 792 -- -- 792 -- --
Stock compensation...................... 3,150 -- -- 3,150 -- --
---------- ----------- ------------ ------------- ----------- -----------
Total operating expenses........... 10,697 (534) -- 10,163 -- --
---------- ----------- ------------ ------------- ----------- -----------
Operating income........................ 2,525 534 477 3,536 -- --
---------- ----------- ------------ ------------- ----------- -----------
Interest expense, net................... 1,206 -- -- 1,206 (954)(g) (118)(g)
Interest income, net.................... (97) -- (135)(j) (232) -- 92 (k)
---------- ----------- ------------ ------------- ----------- -----------
Net income before income taxes.......... 1,416 534 612 2,562 (954) 26
Income tax expense...................... 1,735 203 (i) 232 (i) 2,170 362 (i) 10 (i)
---------- ----------- ------------ ------------- ----------- -----------
Net income (loss)....................... $ (319) $ 331 $ 380 $ 392 $ 592 $ 16
========== =========== ============ ============= =========== ===========
Net income (loss) per share............. $ (0.03)
==========
Common stock and common stock
equivalents outstanding............... 9,156
</TABLE>
ADJUSTMENTS
FOR PENDING
FUNDS
ACQUISITION PRO FORMA
------------ ----------

REVENUES
Oil and natural gas..................... $3,756(l) $ 16,538
IPF Activities.......................... -- 732
Other................................... -- 185
------------ ----------
Total revenues..................... 3,756 17,455
------------ ----------
EXPENSES
Lease operating......................... 1,018(l) 4,078
Production and severance taxes.......... 56(l) 469
Depreciation, depletion and
amortization.......................... 1,298(l) 4,046
General and administrative.............. 36(l) 828
Stock compensation...................... -- 3,150
------------ ----------
Total operating expenses........... 2,408 12,571
------------ ----------
Operating income........................ 1,348 4,884
------------ ----------
Interest expense, net................... -- 134
Interest income, net.................... -- (140)
------------ ----------
Net income before income taxes.......... 1,348 4,890
Income tax expense...................... 512(i) 3,054
------------ ----------
Net income (loss)....................... $ 836 $ 1,836
============ ==========
Net income (loss) per share............. $ 0.12
==========
Common stock and common stock
equivalents outstanding............... 15,156(m)
==========

The accompanying notes are an integral part of the pro forma financial
statements.

25
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS
(UNAUDITED)

BASIS OF PRESENTATION

The following pro forma adjustments have been prepared as if the
Transactions had taken place on March 31, 1997 in the case of the pro forma
balance sheet or as of January 1, 1996 in the case of the pro forma statements
of income. The adjustments are based upon currently available information and
certain estimates and assumptions, and therefore the actual adjustments made to
effect the Transactions may differ from the pro forma adjustments. However,
management believes that the assumptions provide a reasonable basis for
presenting the significant effects of the Transactions as contemplated and that
the pro forma adjustments give appropriate effect to these assumptions and are
properly applied in the pro forma financial information.

PRO FORMA ADJUSTMENTS TO THE BALANCE SHEET

a. Reflects the issuance in April 1997 of 95,696 shares of Common Stock at
$4.18 per share pursuant to a private offering made to the employees of the
Company prior to the Offering. For the sale of such shares the Company
received $400,000 in cash and in April 1997 recorded compensation expense
of $0.8 million.

b. Reflects the sale on April 9, 1997 of the Company's ownership interest in
Michigan Production Company, L.L.C. and Michigan Energy Company, L.L.C.
(the "Michigan Development Project") pursuant to the Michigan
Disposition. The Company's interest in both entities was accounted for
using the equity method of accounting. The Company received total
consideration of approximately $7.6 million, consisting of approximately
$2.2 million in cash and a note receivable of $5.4 million bearing interest
at a rate of 10% for the initial six months and 15% thereafter to maturity.

c. Reflects (i) the proceeds from the issuance of 6,000,000 shares of Common
Stock at $13.50 per share pursuant to the Offering and (ii) use of the
proceeds as summarized below (in millions):

Proceeds from the Offering.............. $ 81.0
Offering expenses....................... (6.7)
---------
Net proceeds.................. $ 74.3
=========
Use of proceeds:
Cash for Funds Acquisition......... $ 30.0
Repayment of long-term debt........ 44.3
---------
Net proceeds.................. $ 74.3
=========

d. Reflects proceeds of $8.7 million from the issuance of 643,037 shares of
Common Stock at $13.50 per share pursuant to a sale to Fund VII to be
completed concurrently with consummation of the Offering and proceeds of
$8.0 million from the sale of the restricted certificate of deposit, which
was purchased with the proceeds of a loan from Fund VII and used as
security for certain obligations related to the Michigan Development
Project. As a result of the sale of the Michigan Development Project
discussed in Note b, the certificate of deposit is no longer restricted and
the Company will use the proceeds from the sale thereof to reduce
outstanding borrowings. Accordingly, the adjustment also reflects the use
of $16.7 million for repayment of indebtedness to Fund VII, payment of
accrued expenses and repayment of debt under the Revolving Credit Facility.

e. Reflects the pending acquisition of the oil and gas properties of the Funds
for $30.0 million. The properties to be acquired consist of net profits
overriding royalty interests owned by three institutional investors that
are not affiliated with the Company. See "Business and
Properties -- Certain Transactions -- The Funds Acquisition."

26
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)

PRO FORMA ADJUSTMENTS TO THE INCOME STATEMENTS

f. Reflects the reduction in the depreciation, depletion, and amortization
rate as a result of the allocation of the Acquisition purchase price in
accordance with the purchase method of accounting. The Company completed
the Acquisition for a total cash purchase price of approximately $96.2
million and the assumption of liabilities of approximately $16.8 million.
The assets and liabilities acquired have been recorded by the Company at
their estimated fair market values, summarized as follows (in thousands):

Assets:
Accounts receivable -- trade....... $ 19,456
IPF Program notes receivable....... 21,710
Oil and gas properties............. 66,176
Other assets....................... 5,658
----------
$ 113,000
==========
Liabilities:
Accounts payable................... $ (10,624)
Long-term debt..................... (6,212)
----------
$ (16,836)
==========

27
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)

g. Reflects the adjustments to interest expense computed as follows (in
thousands):
1. Year Ended December 31, 1996
(a) Historical

<TABLE>
<CAPTION>
BEFORE AFTER
PAYMENT PAYMENT RATE INTEREST
------- -------- --------- --------
<S> <C> <C> <C> <C>
IPF Company Credit Facility....... $ 6,212 $ 6,212 8.00% $ 150(i)
--------
$ 150
--------
</TABLE>
(b) The Company was capitalized on December 31, 1996 with the issuance of
7,177,681 shares of Common Stock for $30.0 million and borrowings of
$61.2 million and $5.0 million under its Revolving Credit Facility and
IPF Company Credit Facility, respectively. As discussed in Note f, the
Company assumed $6.2 million of long-term debt in connection with the
Acquisition.

<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
The Acquisition Financing:
Revolving Credit Facility........ $ -- $ 61,200 8.00% $ 4,896
IPF Company Credit Facility...... 6,212 11,212 8.00% 400
Indebtedness to Fund VII......... -- 8,000 4.60% 368
Average historical indebtedness
to Predecessor Parent(ii)..... -- 118,500 8.00% 9,480
Less: amounts capitalized on
$12.6 million of properties
not subject to amortization... -- -- 8.00% (1,013)
--------
$ 14,131
--------
(c) Repayment of debt using Offering
proceeds:
Revolving Credit Facility......... $61,200 $ 21,870 7.00%(iii)$ (3,365)
IPF Company Credit Facility....... 11,212 6,212 8.00% (400)
--------
$ (3,765)
--------
(d) Repayment of debt using proceeds
from Concurrent Sale:
Revolving Credit Facility........ $21,870 $ 13,870 7.00%(iii)$ (608)
Indebtedness to Fund VII......... 8,000 -- 4.60% (368)
--------
$ (976)
--------
Total pro forma interest expense
adjusted...................... $ 9,540
========
</TABLE>
A 1/8% increase in the variable interest rates on the above debt instruments
would decrease net income by $98,000.

28
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)

2. Three Months Ended March 31, 1997

<TABLE>
<CAPTION>
BALANCE
BEGINNING BALANCE
OF END OF
PERIOD PERIOD RATE INTEREST
------- -------- --------- --------
<S> <C> <C> <C> <C>
(a) Historical:
Revolving Credit
Facility................. $61,200 $ 59,500 8.00% $ 1,228
IPF Company Credit
Facility................. 11,212 17,338 8.00% 222(i)
Indebtedness to Fund VII... 8,000 8,000 4.60% 92
Less: Amount capitalized
on $12.6 million of
properties not subject to
amortization............. -- -- 8.00% (336)
--------
$ 1,206
--------
(b) Repayment of debt using
Offering Proceeds:
Revolving Credit
Facility................. $59,500 $ 20,170 7.00%(iii) $ (856)
IPF Company Credit
Facility................. 17,338 12,338 8.00% (98)
--------
$ (954)
========
(c) Repayment of debt using
proceeds of Concurrent Sale:
Revolving Credit
Facility................. $20,170 $ 12,170 7.00% ($ 152)
Indebtedness to Fund VII... 8,000 -- 4.60% (92)
Adjustment to amounts
capitalized for reduction
in interest rate(iii).... -- -- 7.00% 126
--------
$ (118)
--------
Total pro forma interest expense
adjusted.............................. $ 134
========
</TABLE>
A 1/8% increase in the variable interests rates on the above debt instruments
would decrease net income by $3,100. In connection with the Acquisition on
December 31, 1996, the Company did not assume the liabilities of the Predecessor
to the Predecessor Parent. Accordingly, for the three months ended March 31,
1997, there is no interest expense related to advances from the Predecessor
Parent as is reflected in pro forma interest expense for the year ended December
31, 1996. ------------ (i) Reflects actual historical interest expense incurred
on IPF Company Credit Facility debt outstanding prior to the Acquisition based
on amounts outstanding from time to time. (ii) The Predecessor Parent did not
charge the Company interest on the funds it advanced to the Company. This
adjustment reflects interest expense that would have accrued on the average
amount of advances from the Predecessor Parent outstanding during 1996 if the
Predecessor Parent had charged the Company interest on such advances. (iii) Once
the total amount of debt outstanding is below the threshold amount as defined by
the Revolving Credit Facility, the interest rate is lowered by 1.0%. See "Notes
to Combined and Consolidated Financial Statements -- Long-term Debt -- Revolving
Credit Facility."

h. Reflects the interest income on a certificate of deposit used as collateral
for the Michigan Development Project.

i. The effective rate of 38.0% is computed using statutory rates, including
state taxes, less the federal income tax benefit derived from state taxes.

j. As discussed in Note b, on April 9, 1997, the Company sold its ownership
interest in two entities accounted for using the equity method of
accounting. This adjustment reflects the effects of the exclusion of the
Company's equity share of the results of operations of these two entities
and the interest income on the note receivable from the sale.

29
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)

k. Reflects reduction in interest income on a certificate of deposit used as
collateral for the Michigan Development Project as a result of the sale of
the certificate of deposit.

l. Reflects the changes in income items from the Funds Acquisition. Revenues
and production expenses were obtained from unaudited historical information
for the Funds. Other pro forma items are calculated on a consolidated
basis. For example, the DD&A adjustment is calculated based on the impact
of the Acquisition on the Company's consolidated DD&A expense rate.

m. Common stock and common stock equivalents outstanding has been calculated
assuming that the 7,177,681 shares of Common Stock purchased in connection
with the Acquisition, the 486,003 shares of Common Stock purchased by the
Company's employees in 1997, the 849,694 shares of Common Stock reserved
for issuance pursuant to outstanding options under the Stock Purchase and
Option Plan, the 6,000,000 shares of Common Stock to be issued pursuant to
the Offering and the 643,037 shares of Common Stock to be issued to Fund
VII pursuant to the Concurrent Sale have been outstanding since January 1,
1996.

30
<PAGE>
SELECTED HISTORICAL COMBINED AND CONSOLIDATED FINANCIAL DATA

The following table sets forth selected historical combined and
consolidated information of the Company for the five years ended and as of
December 31, 1996 and for the three months ended March 31, 1996 and 1997 and as
of March 31, 1997. The results for the three months ended March 31, 1997 are not
necessarily indicative of the results for the full year. The selected combined
and consolidated financial data should be read in conjunction with
"Capitalization," "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Combined and Consolidated Financial
Statements of the Company and the related notes thereto included elsewhere in
this Prospectus.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
-------------------------------------------------------- -----------------------
PREDECESSOR PREDECESSOR SUCCESSOR
-------------------------------------------------------- ----------- ---------
1992 1993 1994 1995 1996 1996 1997
--------- --------- ---------- ---------- ---------- ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and natural gas sales(1)....... $ 2 $ 1,922 $ 5,340 $ 34,877 $ 52,274 $15,688 $ 12,782
IPF Activities(2).................. -- 200 1,417 2,356 4,369 340 732
Other.............................. -- -- 283 414 (413) 115 (292)
--------- --------- ---------- ---------- ---------- ----------- ---------
Total revenues................ 2 2,122 7,040 37,647 56,230 16,143 13,222
--------- --------- ---------- ---------- ---------- ----------- ---------
Expenses:
Lease operating.................... -- 218 1,790 7,980 10,207 2,127 3,060
Production and severance taxes..... -- 2 18 710 1,340 279 413
Depreciation, depletion and
amortization..................... -- 987 3,101 22,692 24,920 7,613 3,282
General and administrative, net.... 332 681 52 2,780 3,361 1,089 792
Corporate overhead allocation...... -- 257 944 2,627 4,827 939 --
Stock compensation................. -- -- -- -- -- -- 3,150
--------- --------- ---------- ---------- ---------- ----------- ---------
Total operating expenses...... 332 2,145 5,905 36,789 44,655 12,047 10,697
--------- --------- ---------- ---------- ---------- ----------- ---------
Income (loss) from operations........... (330) (23) 1,135 858 11,575 4,096 2,525
Interest expense, net................... 20 -- -- -- 150 -- 1,109
--------- --------- ---------- ---------- ---------- ----------- ---------
Income (loss) before income taxes....... (350) (23) 1,135 858 11,425 4,096 1,416
Income tax provision (benefit).......... (119) 2 735 351 4,394 1,342 1,735
--------- --------- ---------- ---------- ---------- ----------- ---------
Net income (loss)....................... $ (231) $ (25) $ 400 $ 507 $ 7,031 $ 2,754 $ (319)
========= ========= ========== ========== ========== =========== =========
Net income (loss) per share............. $ (0.03)
=========
Common stock and common stock
equivalents outstanding............... 9,156
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------------------------
PREDECESSOR SUCCESSOR
-------------------------------------------- SUCCESSOR AS OF MARCH 31,
1992 1993 1994 1995 1996 1997
--------- --------- ---------- ---------- ---------- ---------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents.......... $ 2 $ 1,635 $ 11,467 $ -- $ 36 $ 6,082
Property, plant and equipment,
net.............................. 131 11,544 93,823 111,724 66,176 63,636
IPF Program notes receivable....... -- 4,215 4,023 7,991 21,710 27,530
Total assets....................... 1,403 23,493 117,755 137,096 122,429 125,664
Long-term debt (including current
maturities)...................... -- -- -- -- 79,412 83,838
Parent advances.................... 1,684 19,491 104,504 112,832 -- --
Stockholders' equity............... (309) (335) 65 572 28,577 32,493
</TABLE>
- ------------

(2) IPF Activities includes income from the Company's IPF Program and the
Company's "GasFund" partnership with a financial investor. See "Business
and Properties -- Producer Investment Activities."

31
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding the
Company's historical financial position and results of operations as of December
31, 1995 and 1996 and for each year of the three-year period ended December 31,
1996 and as of March 31, 1997, and for the three months ended March 31, 1996 and
1997. The Company's historical financial statements and notes thereto included
elsewhere in this Prospectus contain detailed information that should be
referred to in conjunction with this discussion.

GENERAL

On December 31, 1996, the Company acquired all of the outstanding capital
stock of its operating subsidiaries, Domain Energy Ventures Corporation
("Ventures Corporation") and Domain Energy Production Corporation ("Production
Corporation" and, together with Ventures Corporation, the "Predecessor"). The
Company has accounted for the acquisition (the "Acquisition") using the purchase
method of accounting, under which the purchase price has been allocated to the
assets acquired and liabilities assumed based upon their fair values at the
acquisition date.

The Company is an independent oil and gas company engaged in the
exploration, development, production and acquisition of domestic oil and natural
gas properties, principally in the Gulf Coast region. The Company complements
these activities with its IPF Program pursuant to which it invests in oil and
natural gas reserves through the acquisition of term overriding royalty
interests accounted for as notes receivable. As of December 31, 1996, the
Company had estimated net proved reserves of 149.6 Bcfe. Approximately 54% of
the Company's net proved reserves at such date were natural gas and
approximately 61% of proved reserves were classified as proved developed
producing. As of December 31, 1996, the Company had a PV-10 Reserve Value of
$184.8 million, which does not include reserve value attributable to the IPF
Program but includes the Company's proportionate share of reserve value
attributable to the Michigan Development Project.

The Company's selected historical combined and consolidated financial data
included elsewhere in this Prospectus have been derived from the audited
Combined and Consolidated Financial Statements of the Company. The selected
balance sheet data at December 31, 1996 reflects the Acquisition that occurred
on that date. The selected balance sheet and income statement data at other
dates and for other periods reflects the combined financial position and results
of operations of Ventures Corporation and Production Corporation with
intercompany transactions and account balances eliminated.

Prior to the Acquisition, these companies and their subsidiaries were
included in the consolidated federal income tax return of Tenneco, as a result
of which Tenneco will receive all benefit for such entities' historical tax
losses. In connection with the Acquisition, the Company agreed to file an
election under Sections 338(g) and 338(h)(10) of the Internal Revenue Code of
1986, as amended, pursuant to which the Company will allocate the purchase price
paid by the Company among the assets of these companies to determine the basis
of assets acquired in accordance with the principles of Treasury Regulation
1.338(h)(10)-1(f)(1)(ii).

32
<PAGE>
The sources and uses of funds related to financing the Acquisition as of
the closing date were as follows:

(IN MILLIONS)
SOURCES OF FUNDS:
Revolving Credit Facility............. $61.2
Common Stock purchased by Fund
VII.................................. 30.0
IPF Company Credit Facility........... 5.0
-------------
$96.2
=============
USE OF FUNDS:
Acquisition purchase price(1)......... $96.2
-------------
$96.2
=============
- ------------

(1) In February 1997 the Company paid an additional $500,000 as a post-closing
adjustment to the Acquisition purchase price.

The Company's objective is to maximize shareholder value by growing
reserves, production, cash flow and earnings through the opportunistic
acquisition of Gulf Coast region properties with underexploited value. The
Company applies 3-D seismic and other advanced technologies to development,
exploitation and exploration. These activities are complemented by the continued
expansion of the IPF Program. Fundamental to the execution of the Company's
strategy is its foundation of experienced technical talent strengthened by a
high level of financial, transactional and risk-management expertise, resulting
in part, from the former association of the Company and its employees with
Tenneco.

The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and natural gas, which
are dependent upon numerous factors beyond the Company's control, such as
economic, political and regulatory developments and competition from other
sources of energy. The energy markets have historically been highly volatile,
and future decreases in oil or natural gas prices could have a material adverse
effect on the Company's financial position, results of operations, quantities of
oil and natural gas reserves that may be economically produced, and access to
capital.

The Company uses the full cost method of accounting for its investments in
oil and natural gas properties. Under such methodology, all costs of
exploration, development and acquisition of oil and natural gas reserves are
capitalized into a "full cost pool" as incurred and properties in the pool are
depleted and charged to operations using the unit-of-production method based on
a ratio of current production to total proved oil and natural gas reserves. To
the extent that such capitalized costs (net of accumulated depreciation,
depletion, and amortization) less deferred taxes exceed the present value (using
a 10% discount rate) of estimated future net cash flows from proved oil and
natural gas reserves and the lower of cost or fair value of unproved properties,
such excess costs are charged to operations. If a write-down were required, it
would result in a non-cash charge to earnings but would not have an impact on
cash flows.

ACCOUNTING FOR IPF PROGRAM ACTIVITY

Through its IPF Program, the Company acquires term overriding royalty
interests in oil and gas properties owned by independent producers. Because the
capital advanced to a producer for these interests is repaid from an agreed upon
share of cash revenues from the sale of production until the capital advanced
plus a contractual return is paid in full, the Company accounts for the term
overriding royalty interests as notes receivable. Under this accounting method,
the Company recognizes only the interest income portion of payments received
from a producer as revenues on its income statement. The remaining cash receipts
are recorded as a reduction in notes receivable on the Company's balance sheet
and as IPF Program return of capital on the Company's statement of cash flows.

If instead of acquiring dollar-denominated term overriding royalty
interests, the Company were purchasing term overriding royalty interests
requiring delivery of a specified quantity of oil and gas, IPF

33
<PAGE>
Program results would be accounted for differently. Specifically, in 1996,
Company EBITDA would increase by $4.3 million and IPF Program return of capital
in the Combined Statement of Cash Flows would decrease by the same amount. To
more accurately reflect the actual cash flows generated by the Company, IPF
Program return of capital is identified separately to allow such cash receipts
to be combined with EBITDA.

Although, to date, the Company has not incurred any losses on notes
outstanding under the IPF Program, as of December 31, 1996, the Company
established a non-cash reserve for potential future losses of $437,000, which
reserve is netted against IPF Program notes receivable in the Company's balance
sheet.

34
<PAGE>
RESULTS OF OPERATIONS

The Company has experienced significant growth in reserves, production,
cash flow and earnings over the past three years. The following table summarizes
certain operating and financial data, production volumes, average realized
prices and average expenses for the Company's oil and natural gas operations for
the years ended December 31, 1994, 1995 and 1996 and the three months ended
March 31, 1996 and 1997:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED
-------------------------------- MARCH 31,
PREDECESSOR ------------------------
-------------------------------- PREDECESSOR SUCCESSOR
1994 1995 1996 1996 1997
---------- --------- --------- ----------- ---------
FINANCIAL DATA (IN THOUSANDS):
<S> <C> <C> <C> <C> <C>
Revenues
Natural gas................... $ 4,101 $ 27,772 $ 41,767 $13,772 $ 10,094
Oil and condensate............ 1,239 7,105 10,507 1,916 2,688
IPF Activities(1)............. 1,417 2,356 4,369 340 732
Total revenues..................... 7,040 37,647 56,230 16,143 13,222
Total operating expenses........... 5,905 36,789 44,655 12,047 10,697
---------- --------- --------- ----------- ---------
Operating income................... $ 1,135 $ 858 $ 11,575 $ 4,096 $ 2,525
========== ========= ========= =========== =========
Net income (loss).................. $ 400 $ 507 $ 7,031 $ 2,754 $ (319)
Net cash provided by operating
activities....................... 11,487 19,933 34,553 5,715 8,112
Net cash used in investing
activities....................... (86,669) (39,728) (47,329) (10,634) (7,577)
Net cash provided by financing
activities....................... 85,014 8,328 12,776 5,285 5,511

NON-GAAP FINANCIAL DATA
(IN THOUSANDS):
EBITDA(2).......................... $ 4,236 $ 23,550 $ 36,495 $11,709 $ 8,957
IPF Program return of capital(3)... 3,507 2,638 4,618 517 3,426
EBITDA plus IPF Program return of
capital.......................... 7,743 26,188 41,113 12,226 12,383

PRODUCTION VOLUMES:
Natural gas (MMcf)................. 2,334 18,065 21,192 5,828 3,668
Oil and condensate (MBbls)......... 83 424 564 116 141
Total (MMcfe)...................... 2,832 20,609 24,575 6,524 4,516

AVERAGE REALIZED PRICES:(4)
Natural gas (per Mcf).............. $ 1.76 $ 1.54 $ 1.97 $ 2.36 $ 2.75
Oil and condensate (per Bbl)....... 14.93 16.76 18.63 16.52 19.06

EXPENSES (PER MCFE):
Lease operating.................... $ 0.63 $ 0.39 $ 0.42 $ 0.33 $ 0.68
Production taxes................... 0.01 0.03 0.05 0.04 0.09
Depreciation, depletion and
amortization..................... 1.03 1.08 1.01 1.19 0.69
General and administrative,
net(5)........................... 0.26 0.16 0.12 0.14 0.14
</TABLE>
- ------------

(1) IPF Activities includes income from the Company's IPF Program and the
Company's "GasFund" partnership with a financial investor. See "Business
and Properties -- Producer Investment Activities."

(FOOTNOTES CONTINUED ON FOLLOWING PAGE)

35
<PAGE>
(2) EBITDA represents earnings before stock compensation expense, interest,
income taxes, depreciation, depletion and amortization. The Company believes
that EBITDA may provide additional information about the Company's ability
to meet its future requirements for debt service, capital expenditures and
working capital. EBITDA is a financial measure commonly used in the oil and
gas industry and should not be considered in isolation or as a substitute
for net income, operating income, net cash provided by operating activities
or any other measure of financial performance presented in accordance with
generally accepted accounting principles or as a measure of a company's
profitability or liquidity. Because EBITDA excludes some, but not all, items
that affect net income and may vary among companies, the EBITDA calculation
presented above may not be comparable to similarly titled measures of other
companies.

(3) To more accurately reflect the actual cash flows generated by the Company,
IPF Program return of capital is identified separately to allow such cash
receipts to be combined with EBITDA.

(4) Reflects the actual realized prices received by the Company, including the
results of the Company's hedging activities. See " -- Other
Matters -- Hedging Activities."

(5) Includes production attributable to properties managed for the Funds for the
periods indicated and excludes fees received from investors and overhead
allocations from Tenneco. Including Tenneco allocations, average net general
and administrative expenses per Mcfe for the years ended December 31, 1994,
1995 and 1996 would be $0.26, $0.20 and $0.28, respectively.

THREE MONTHS ENDED MARCH 31, 1997 COMPARED TO THREE MONTHS ENDED MARCH 31,
1996

Oil and natural gas revenues decreased from $15.7 million in the first
quarter of 1996 to $12.8 million in the first quarter of 1997, a decrease of
$2.9 million, or 18.5%. Production volumes for oil and condensate increased from
116 MBbls in the first quarter of 1996 to 141 MBbls in the first quarter of
1997, an increase of 25 MBbls, or 21.6%. Production volumes for natural gas
decreased from 5.8 Bcf in the first quarter of 1996 to 3.7 Bcf in the first
quarter of 1997, a decrease of 2.2 Bcf, or 37.1%. The decrease in natural gas
production was primarily due to the sale of the ATP Partnership and Cage Ranch
properties as well as natural declines in production from the Mustang Island 847
Field, the West Cameron 601 Field, the Eugene Island Field and the Rabbit Island
Field. The decrease in total net production decreased revenues by $4.7 million.
This was partially offset by a 15.4% increase in oil and condensate prices and a
16.5% increase in natural gas prices. Increases in average oil and natural gas
prices were attributable to improved market conditions for oil and natural gas
and improved results from natural gas hedging activities.

As a result of hedging activities, the Company realized an average oil
price of $19.06 per Bbl and an average gas price of $2.75 per Mcf for the first
quarter of 1997, compared to average prices of $21.45 per Bbl and $2.73 per Mcf,
respectively, that otherwise would have been received. For the first quarter of
1996, as a result of hedging activities the Company realized an average oil
price of $16.52 per Bbl and an average gas price of $2.36 per Mcf, compared to
average prices of $17.80 per Bbl and $2.57 per Mcf, respectively, that otherwise
would have been received.

Revenues from IPF Activities increased from $0.3 million in the first
quarter of 1996 to $0.7 million in the first quarter of 1997, an increase of
$0.4 million, or 115.3%. This was the result of increased activities in the IPF
Program. See "Business and Properties -- Producer Investment Activities."

Lease operating expenses increased from $2.1 million in the first quarter
of 1996 to $3.1 million in the first quarter of 1997, an increase of $1.0
million or 43.9%. On an Mcfe basis, lease operating expenses increased from
$0.33 in the first quarter of 1996 to $0.68 in the first quarter of 1997, an
increase of $0.35, or 106.1%. Lease operating expenses were higher in the first
quarter of 1997 as compared to the first quarter of 1996 as a result of the
Wasson Field acquisition completed by the Company after the first quarter of
1996. The Wasson Field, which is in tertiary recovery, had a relatively low
purchase price based on reserves, which is offset by relatively high lease
operating expenses.

Depreciation, depletion and amortization ("DD&A") expense declined from
$7.6 million in the first quarter of 1996 to $3.3 million in the first quarter
of 1997, a decrease of $4.3 million, or 56.9%. This was the result of lower oil
and gas production volumes and a 42.0% decrease in the DD&A rate. The reduced
DD&A rate was the result of reduced cost basis attributable to the Company's oil
and gas properties purchased in the Acquisition. See "Business and Properties --
The Company."

General and administrative expense decreased from $1.1 million in the first
quarter of 1996 to $0.8 million in the first quarter of 1997, a decrease of $0.3
million, or 27.3%. This decrease was primarily due to a reduction in the number
of employees.

36
<PAGE>
The corporate overhead allocation decreased from $0.9 million in the first
quarter of 1996 to zero in the first quarter of 1997 due to the Acquisition and
the elimination of Tenneco's allocated overhead.

Stock compensation increased from zero in the first quarter of 1996 to $3.2
million in the first quarter of 1997 due to the implementation of the Stock
Purchase and Option Plan.

Income tax expense increased from $1.3 million in the first quarter of 1996
to $1.7 million in the first quarter of 1997, an increase of $0.4 million or
29.3%. This increase was primarily due to an increase in the effective tax rate
from 32.8% in the first quarter of 1996 to 122.5% in the first quarter of 1997
due to the exclusion of stock compensation expense in the 1997 tax calculation.
This increase in income tax expense was partially offset by a decrease in the
income before taxes from $4.1 million in the first quarter of 1996 to $1.4
million in the first quarter of 1997.

Net income was $2.8 million in the first quarter of 1996 compared to a net
loss of $0.3 million in the first quarter of 1997 as a result of the factors
described above.

YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995

Oil and natural gas revenues increased from $34.9 million in 1995 to $52.3
million in 1996, an increase of $17.4 million, or 49.9%. Production volumes for
oil and condensate increased from 424 MBbls in 1995 to 564 MBbls in 1996, an
increase of 140 MBbls, or 33.0%. Production volumes for natural gas increased
from 18.1 Bcf in 1995 to 21.2 Bcf in 1996, an increase of 3.1 Bcf, or 17.3%. The
increase in oil and natural gas production was due to new wells being
successfully drilled and completed during 1996, as well as acquisitions of
producing properties. The increase in total net production increased revenues by
$7.2 million. In addition, the Company experienced a 11.2% increase in average
oil and condensate prices and a 27.9% increase in average natural gas prices.
Increases in average oil and natural gas prices were directly attributable to
general improved market conditions.

As a result of hedging activities, the Company realized an average oil
price of $18.63 per Bbl and an average gas price of $1.97 per Mcf for the year
ended December 31, 1996, compared to average prices of $20.88 per Bbl and $2.41
per Mcf, respectively, that otherwise would have been received. These hedging
activities decreased oil and natural gas revenues by approximately $10.5
million. This loss of revenue was the result of hedges made at the direction of
Tenneco in late 1995.

Revenues from IPF Activities increased from $2.4 million in 1995 to $4.4
million in 1996, an increase of $2.0 million, or 85.4%. This increase was the
result of a $1.0 million increase in IPF Program revenues and a $1.0 million
increase in GasFund revenues. See "Business and Properties -- Producer
Investment Activities." IPF Program revenues increased as the result of an
increase in IPF Program investments attributable to a 100% increase in IPF
Program customers at year-end 1996 compared to year-end 1995.

Lease operating expenses increased from $8.0 million in 1995 to $10.2
million in 1996, an increase of $2.2 million, or 27.9%. On an Mcfe basis, lease
operating expenses increased from $0.39 in 1995 to $0.42 in 1996, an increase of
$0.03, or 7.7%. The increase in lease operating expenses was primarily
attributable to increased production volumes. On a per unit basis, the increase
was primarily attributable to the acquisition in June 1996 of an interest in the
Wasson Field, which is undergoing tertiary enhanced recovery and the expenses
associated therewith.

Depreciation, depletion and amortization ("DD&A") expense increased from
$22.7 million in 1995 to $24.9 million, an increase of $2.2 million. This was
the result of higher oil and gas production volumes partially offset by a 6.5%
decrease in the DD&A rate. The reduced DD&A rate was attributable to the
acquisition of low cost reserves in the Wasson Field.

General and administrative expense increased from $2.8 million in 1995 to
$3.4 million in 1996, an increase of $0.6 million, or 20.9%. This increase
reflects a decrease in the reimbursement of overhead paid to the Company by the
investors in the Funds from $1.1 million in 1995 to zero in 1996 partially
offset by an increase in the capitalization of general and administrative
expense in 1996 by $0.5 million as compared to 1995.

37
<PAGE>
The corporate overhead allocation increased from $2.6 million in 1995 to
$4.8 million in 1996, an increase of $2.2 million, or 83.7%. The increase was
primarily due to approximately $2.0 million in costs related to severance
payments, retention bonuses and other costs associated with the merger of
Tenneco with an affiliate of El Paso Natural Gas Company.

Income tax expense increased from $0.4 million in 1995 to $4.4 million in
1996, an increase of $4.0 million, or 1152%. This was due to an increase in
income before taxes from $0.9 million in 1995 to $11.4 million in 1996 and an
increase in the effective tax rate from 40.9% in 1995 to 38.5% in 1996.

Net income was $0.5 million in 1995 compared to $7.0 million in 1996, as a
result of the factors described above.

YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994

Oil and natural gas revenues increased from $5.3 million in 1994 to $34.9
million in 1995, an increase of $29.5 million, or 553%. Production volumes for
oil and condensate increased from 83 MBbls in 1994 to 424 MBbls in 1995, an
increase of 341 MBbls, or 411%. Production volumes for natural gas increased
from 2.3 Bcf in 1994 to 18.1 Bcf in 1995, an increase of 15.7 Bcf, or 674%. The
increase in oil and natural gas production was due to increased drilling
activities, as well as the Pennzoil Acquisition and other acquisitions of
producing properties. The increase in total net production increased revenues by
$32.8 million. In addition, the Company experienced a 12.3% increase in average
oil and condensate prices, and a 12.5% decrease in average natural gas prices.

As a result of hedging activities, the Company realized an average oil
price of $16.76 per Bbl for the year ended December 31, 1995, compared to an
average price of $16.31 per Bbl that otherwise would have been received. These
hedging activities increased oil revenues by approximately $0.2 million.

Revenues from IPF Activities increased from $1.4 million in 1994 to $2.4
million in 1995, an increase of $0.9 million, or 66.3%. This increase was
primarily attributable to GasFund loan activity. See "Business and
Properties -- Producer Investment Activities."

Lease operating expenses increased from $1.8 million in 1994 to $8.0
million in 1995, an increase of $6.2 million, or 346%. However, on an Mcfe
basis, lease operating expenses decreased from $0.63 in 1994 to $0.39 in 1995, a
decrease of $0.24, or 38%. The decrease in lease operating cost per Mcfe was
primarily attributable to significant increases in production volumes, following
several substantial asset acquisitions.

DD&A expense increased from $3.1 million in 1994 to $22.7 million in 1995,
an increase of $19.6 million, or 632%. This increase was due to the increase in
oil and gas production volumes and an increase in the DD&A rate per Mcfe from
$1.03 in 1994 to $1.08 in 1995, a 5.0% increase. The 1994 DD&A rate was
adversely affected by a downward revision in the prior year's estimate of oil
and gas reserves. The downward revision was primarily caused by negative
drilling results by the Company in an offshore field. The increase in DD&A rate
per Mcfe in 1995 is the result of higher finding costs relative to 1994 ($1.13
in 1995 compared to $0.91 in 1994).

General and administrative expense increased from $0.1 million in 1994 to
$2.8 million in 1995, an increase of $2.7 million. Net general and
administrative expense in 1994 was nominal because direct expenses of $3.5
million were offset by $1.8 million of overhead reimbursement paid to the
Company by investors in the Funds and $1.6 million of capitalized general and
administrative expense. The increase in 1995 was primarily attributable to
salary, benefits, rent and related costs of the additional 24 employees hired
during 1995 due to acquisitions and increased business activity.

The corporate overhead allocation increased from $0.9 in 1994 to $2.6
million in 1995, an increase of $1.7 million. The increase was based on the
Company's increased business activities resulting from acquisitions.

Income tax expense decreased from $0.7 million in 1994 to $0.4 million in
1995, a decrease of $0.4 million, or 52.2%. This was primarily due to a decrease
in the effective tax rate from 64.8% in 1994 to 40.9% in 1995.

38
<PAGE>
Net income was $0.4 million in 1994 compared to $0.5 million in 1995, as a
result of the factors described above.

LIQUIDITY AND CAPITAL RESOURCES

Cash flows provided by operating activities from the Predecessor's
operations were $11.5 million, $19.9 million and $34.6 million for each of the
three years in the periods ended December 31, 1994, 1995 and 1996, respectively.
Significant increases in production resulting from oil and gas property
acquisitions over this three year period increased net income. Cash flows from
the Predecessor's operations for the three months ended March 31, 1996 were $5.7
million and for the Company's operations for the three months ended March 31,
1997 were $8.1 million. This increase was primarily attributable to changes in
operating assets and liabilities in 1997 partially offset by production declines
due to the sale of certain properties as well as natural declines in production
from certain fields.

Cash flows used in investing activities by the Predecessor were $86.7
million, $39.7 million and $47.3 million for each of the three years in the
periods ended December 31, 1994, 1995 and 1996, respectively. Property additions
through acquisition, exploration and development activities and increasing IPF
Program activity levels were the primary reasons for the use of funds in
investing activities. Partially offsetting these uses of funds were proceeds
from sales of non-core oil and gas properties of $8.3 million and $1.5 million
in 1995 and 1996, respectively. Cash flows used in investing activities by the
Predecessor for the three months ended March 31, 1996 were $10.6 million and by
the Company for the three months ended March 31, 1997 were $7.6 million. In both
first quarter periods, the uses resulted from expanding acquisition,
exploration, development and IPF Program activities partially offset by the sale
of non-core oil and gas properties.

Cash flows provided by the Predecessor's financing activities were $85.0
million, $8.3 million and $12.8 million for each of the three years in the
periods ended December 31, 1994, 1995 and 1996, respectively. In 1994 and 1995
the cash flows were provided by parent advances. In 1996, $6.2 million was
generated from the IPF Company Credit Facility and $6.6 million was provided by
parent advances. Cash flows provided by the Predecessor's financing activities
for the three months ended March 31, 1996 were $5.3 million, which were provided
by parent advances. Cash flows provided by financing activities for the
Company's operations for the three months ended March 31, 1997 were $5.5
million, consisting of additional net borrowings of $4.4 million and proceeds
from the sale of Common Stock to management of the Company of $1.1 million.

Funding for the Company's exploration and development activities,
acquisitions and IPF Program investments has historically been provided by
operating cash flows, revolving credit borrowings, asset sales and advances from
Tenneco. The Company's Board of Directors has authorized a capital budget of
$125.0 million for 1997 to be spent on exploratory and development drilling, IPF
Program investments and acquisitions of oil and gas properties. The Company
intends to finance these expenditures with a portion of the net proceeds from
this Offering, cash flow from operations and borrowings under its revolving
credit facilities.

As a result of borrowings under the Revolving Credit Facility and the IPF
Company Credit Facility in order to finance a portion of the costs of the
Acquisition, the Company has incurred substantial indebtedness and has minimal
borrowing availability under either of such facilities. As of March 31, 1997,
the Company had total consolidated indebtedness for money borrowed of
approximately $83.8 million. On a pro forma basis as of March 31, 1997, the
Company would have had total consolidated indebtedness for money borrowed of
approximately $24.5 million, resulting in availability for additional borrowings
of $51.1 million and $5.7 million under the Revolving Credit Facility and the
IPF Company Credit Facility, respectively (assuming a borrowing base of $63.3
million and $18.0 million, respectively).

The borrowing base under the Revolving Credit Facility may be redetermined
by the Lenders at any time and is scheduled to be redetermined based on the
Company's January 1 and June 30 reserve reports. Depending on the price outlook
for oil and natural gas and the levels of the Company's cash flows and capital
expenditures, the borrowing base may be re-set below the amounts outstanding
under the Revolving

39
<PAGE>
Credit Facility, and in such case the Company may need to refinance a portion of
the principal amount of such indebtedness prior to its maturity. The Company
believes that cash flow from operations, proceeds from the Offering and
revolving credit borrowings will be adequate to meet future liquidity needs,
including satisfying the Company's financial obligations and funding its capital
investment program.

At December 31, 1996, the Company had a working capital deficit of
approximately $2.1 million, primarily due to current maturities of long-term
debt. At March 31, 1997, on a pro forma basis after giving effect to the
disposition of the Michigan properties and the sale of 95,696 shares of Common
Stock to the Company's employees in April 1997, the Company had working capital
of approximately $9.8 million. After consummation of the other contemplated
transactions described in this Prospectus -- the Offering, the concurrent sale
of stock to Fund VII and the Funds Acquisition -- the Company will have a
significant amount of working capital.

REVOLVING CREDIT FACILITY. In connection with the Acquisition, the Company
entered into the $65.0 million Revolving Credit Facility maturing on December
31, 1999 with a group of banks led by The Chase Manhattan Bank (the "Lenders").
As of March 31, 1997, borrowings outstanding under the Revolving Credit Facility
totalled $59.5 million. The Revolving Credit Facility is secured by
approximately 80% of the aggregate value of the Company's oil and gas properties
and substantially all of the Company's other property (other than IPF Program
properties), including the capital stock of Ventures Corporation and Production
Corporation. Although the remaining approximately 20% of the aggregate value of
the Company's oil and natural gas properties is not mortgaged to the Lenders
thereunder, such properties are nevertheless subject to the restrictions set
forth therein, including a prohibition on granting any security interests
therein. The borrowing base under the facility was $63.3 million as of March 31,
1997, and is subject to a scheduled redetermination every six months (and such
other redeterminations as the Lenders may elect to perform each year) by the
Lenders at the Lenders' sole discretion and in accordance with their customary
practices and standards in effect from time to time for reserve-based loans to
borrowers similar to the Company. Determination of the borrowing base may be
affected by, among other things, estimates and projections of reserves and
production rates with respect to the Company's oil and natural gas properties
and changes in oil and natural gas prices. The Company's obligations under the
Revolving Credit Facility are guaranteed by its wholly-owned subsidiaries,
Ventures Corporation and Production Corporation.

If the Company's borrowing base is reduced, the amount available to the
Company under the Revolving Credit Facility will be reduced and, to the extent
that the borrowing base is less than the amount then outstanding thereunder, the
Company will be obligated to provide additional collateral or prepay such excess
amount within 30 days following the date on which the excess amount first
occurred. The borrowing base under the Revolving Credit Facility is scheduled to
be redetermined as of December 31, 1997 and may be reduced substantially from
its current level. All amounts outstanding in excess of such reduced borrowing
base must be paid in full at such date. In addition, if at the end of any fiscal
quarter of the Company during 1997 the amount then outstanding thereunder
exceeds $43.3 million (as such amount may be adjusted from time to time pursuant
to the Revolving Credit Facility), the Company will be obligated to prepay the
outstanding indebtedness thereunder in an amount equal to 100% of the Company's
"excess cash flow" (as defined therein) for such fiscal quarter. Excess cash
flow is defined to include a portion of the net proceeds to the Company of the
Offering.

Absent a default or an event of default (as defined therein), borrowings
under the Revolving Credit Facility accrue interest at LIBOR plus a margin of
1.50% to 2.50% per annum depending on the total amount outstanding or, at the
option of the Company, at the greater of (i) the prime rate and (ii) the federal
funds effective rate plus 0.50%, plus a margin of 0.50% to 1.50% depending on
the total amount outstanding. The Company incurs a quarterly commitment fee
ranging from 0.375% to 0.50% per annum on the average unused portion of the
Lenders' aggregate commitment, depending on the total amount outstanding.

The Revolving Credit Facility contains a number of covenants that, among
other things, restrict the ability of the Company to dispose of assets, incur
additional indebtedness or grant liens on its properties, repay other
indebtedness, pay dividends, enter into certain investments or acquisitions,
repurchase or

40
<PAGE>
redeem capital stock, engage in mergers or consolidations, or engage in certain
transactions with subsidiaries and affiliates and that will otherwise restrict
corporate activities. In addition, such facility requires the Company to
maintain a specified minimum tangible net worth and to comply with certain
prescribed financial ratios. Further, under such facility, an event of default
is deemed to occur if any person, other than the Company's officers, Fund VII or
any other investment fund, the managing general partner of which is First
Reserve, becomes the beneficial owner, directly or indirectly, of more than 40%
of the outstanding shares of Common Stock.

IPF COMPANY CREDIT FACILITY. IPF Company, an indirect wholly-owned
subsidiary of the Company, has a $100.0 million revolving credit facility with
Compass Bank-Houston pursuant to which it finances a portion of the IPF Program.
The IPF Company Credit Facility matures June 1, 1999 at which time all amounts
owed thereunder are due and payable. The IPF Company Credit Facility is secured
by substantially all of IPF Company's oil and gas interests, including the notes
receivable generated therefrom. IPF Company's obligations under such facility
are nonrecourse to the Company. The borrowing base under the facility as of
March 31, 1997 was $18.0 million and is subject to a scheduled redetermination
by the lender every six months and such other redeterminations as the lender may
elect to perform each year. Effective as of May 7, 1997, the borrowing base
under the facility was increased to $23.0 million. As of March 31, 1997,
approximately $17.3 million was outstanding under the IPF Company Credit
Facility. So long as no default or event of default (as defined therein) is
outstanding, borrowings under the IPF Company Credit Facility accrue interest at
LIBOR plus a margin of 2.25% or, at the option of IPF Company, the prime rate
published in THE WALL STREET JOURNAL. IPF Company incurs a quarterly commitment
fee based on the difference between amounts outstanding under the facility and
the borrowing base.

The IPF Company Credit Facility contains a number of covenants that, among
other things, restrict the ability of IPF Company to incur additional
indebtedness or grant liens on its properties, guarantee indebtedness of any
other person, dispose of assets, make loans in excess of $100,000 other than in
the ordinary course of its business, issue additional shares of capital stock,
engage in certain transactions with affiliates, enter into any new line of
business or amend certain of its material contracts. In addition, such facility
requires IPF Company to maintain a specified minimum tangible net worth.

The IPF Company Credit Facility restricts the ability of IPF Company to
dividend cash to its parent, Ventures Corporation, or otherwise advance cash to
the Company. As of March 31, 1997, IPF Company net assets of approximately $10.0
million were restricted under the IPF Company Credit Facility.

CAPITAL EXPENDITURES AND FUTURE OUTLOOK

The following table sets forth the Company's capital expenditures and IPF
Program investments for each of the past three years.

YEAR ENDED DECEMBER 31,
-------------------------------
PREDECESSOR
-------------------------------
1994 1995 1996
--------- --------- ---------
(IN THOUSANDS)
Acquisition of oil and gas properties... $ 65,201 $ 18,393 $ 8,513
Development and exploitation............ 4,883 7,834 7,506
Exploration............................. 15,121 23,677 12,126
IPF Program investments................. 3,315 6,606 18,608
--------- --------- ---------
Total.............................. $ 88,520 $ 56,510 $ 46,753
========= ========= =========

The Company's Board of Directors has authorized a capital budget of $125.0
million for 1997. The Company expects that $29.0 million of such capital
expenditures will be spent on completion, development and exploitation
activities on 10 Gulf of Mexico lease-blocks and drilling in connection with six
exploratory programs. In addition, the Company expects to invest $36.0 million
in new IPF Program assets. The balance of projected capital expenditures is
attributable to $60.0 million in acquisitions in the Company's core operating
area, $30.0 million of which will be used to finance the Funds Acquisition. The
Company expects to finance these expenditures with proceeds from the Offering,
cash flow from operations and borrowings under the Company's revolving credit
facilities.

41
<PAGE>
Although certain of the Company's costs and expenses may be affected by
inflation, inflationary costs have not had a significant effect on the Company's
results of operations.

OTHER MATTERS

HEDGING ACTIVITIES. In an effort to achieve more predictable cash flows and
earnings and reduce the effects of the volatility of the price of oil and
natural gas on the Company's operations, the Company has in the past and may in
the future hedge oil and natural gas prices through the use of commodity
futures, options and swap agreements and other hedge devices. While the use of
these hedging arrangements limits the downside risk of adverse price movements,
it may also limit future gains from favorable movements. The Company accounts
for these transactions as hedging activities and, accordingly, gains and losses
are included in oil and natural gas revenues in the period in which the related
production occurs. The Company does not engage in speculative hedges. The
Revolving Credit Facility imposes certain limitations on the Company's ability
to enter into hedging transactions, but such limitations are not expected to
constrain the Company's hedging activities in any material respect.

The annual average oil and natural gas prices received by the Company have
fluctuated significantly over the past three years. The Company's weighted
average natural gas price received per Mcf (including the effects of hedging
transactions) was $1.76, $1.54 and $1.97 during the years ended December 31,
1994, 1995, and 1996, respectively. Hedging transactions resulted in a $0.44
reduction in the Company's weighted average natural gas price received per Mcf
in 1996. The Company's weighted average oil price received per Bbl during the
years ended December 31, 1994, 1995 and 1996 was $14.93, $16.76 and $18.63,
respectively. Hedging transactions resulted in a $2.25 reduction in the
Company's weighted average oil price received per Bbl in 1996.

The following table sets forth the Company's open hedging contracts for oil
and natural gas and the corresponding weighted average prices to be received
under various swap agreements as of March 31, 1997 and, assuming a market price
based on the NYMEX twelve-month strip as of March 31, 1997, the Company's
projected results from hedging activities from April 1997 to 2000.

<TABLE>
<CAPTION>
OIL NATURAL GAS
--------------------- ------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
BBLS PRICE MMBTU PRICE
--------- -------- ----- --------
<S> <C> <C> <C> <C>
April 1997 through December 1997........ 184,240 $17.43 7,640 $2.07
January 1998 through December 2000...... 442,550 $18.37 -- --
Projected Results: April 1997
through December 2000 (in
thousands)............................ $ (1,411) $ 698
</TABLE>
The following table sets forth the increase (decrease) in the Company's oil
and natural gas revenues as a result of hedging transactions and the effects of
hedging transactions on price per Mcf and price per Bbl during the periods
indicated. The Company's hedging transactions in 1995 and 1996 were made at the
direction of the management of Tenneco.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------- -----------------------
PREDECESSOR PREDECESSOR SUCCESSOR
------------------------------- ----------- ---------
1994 1995 1996 1996 1997
--------- --------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
Increase (decrease) in natural gas sales
(in thousands)........................ $ -- $ -- $ (9,241) $(1,239) $ 71
Increase (decrease) in oil sales (in
thousands)............................ -- 189 (1,269) (149) (337)
Effect of hedging transactions on
average gas sales price (per Mcf)..... -- -- (0.44) (0.21) 0.02
Effect of hedging transactions on
average oil sales price (per Bbl)..... -- 0.45 (2.25) (1.28) (2.39)
</TABLE>
42
<PAGE>
NATURAL GAS BALANCING. The Company incurs certain gas production volume
imbalances in the ordinary course of business and utilizes the sales method to
account for such imbalances. Under this method, income is recorded based on the
Company's net revenue interest in production taken for delivery. Management does
not believe that the Company had any material gas imbalances as of December 31,
1995 or 1996.

ACCOUNTING PRONOUNCEMENTS. On October 23, 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation" ("SFAS 123"), which establishes a fair
value method for accounting for stock-based compensation plans either through
recognition or disclosure. SFAS 123 encourages, but does not require, companies
to adopt the fair value method of accounting in place of the existing intrinsic
value method of accounting for stock-based compensation. The Company currently
utilizes the intrinsic value method of accounting and will continue to use this
method. When applicable, the Company will disclose the pro forma adjustments to
net income and earnings per share as required by SFAS 123 in the notes to the
Combined and Consolidated Financial Statements of the Company included elsewhere
in this Prospectus.

BUSINESS AND PROPERTIES
THE COMPANY

The Company's pro forma estimated net proved reserves as of December 31,
1996 were 153.8 Bcfe, and its pro forma average daily production during 1996 was
85.6 MMcfe, each of which represents a twelvefold increase from levels in 1993.
Approximately 54% of these reserves were natural gas, and approximately 67% of
proved reserves were classified as proved developed producing. On a pro forma
basis as of December 31, 1996, the Company had a PV-10 Reserve Value of $213.0
million, which does not include reserve value attributable to the IPF Program.

43
<PAGE>
Through the IPF Program, the Company complements its exploration and
production activities by providing capital to independent producers in return
for term overriding royalty interests in oil and gas properties owned by such
producers. From its inception in 1993 through December 31, 1996, the IPF Program
has generated an average return on net assets of approximately 19%. In addition,
the Company believes that the IPF Program offers a lower level of reserve,
production and price risk than that associated with working interest ownership.
From inception through December 31, 1996, the Company completed 40 transactions
under its IPF Program. At December 31, 1996, based on Company estimates and
assuming prices of $2.10 per Mcf of natural gas and $21.00 per Bbl of oil, the
net present value attributable to IPF Program assets was $25.4 million.

The Company reported net income of $7.0 million, $0.5 million and $0.4
million in 1996, 1995 and 1994, respectively. The Company reported unaudited net
loss of $0.3 million and unaudited net income of $2.8 million for the
three-month periods ended March 31, 1997 and 1996, respectively. Based on
unaudited financial information available to the Company for the period from
April 1, 1997 to the date of this Prospectus, the Company estimates that it will
report net income (loss) on approximately a "break-even" basis for the
three-month period ended June 30, 1997. Pro forma net income for the year ended
December 31, 1996 was $11.8 million. See "Prospectus Summary -- Summary
Historical and Pro Forma Combined and Consolidated Financial Data."

The Company's principal executive offices are located at 1100 Louisiana,
Suite 1500, Houston, Texas 77002 and its telephone number is (713) 757-5662. The
mailing address of the Company's principal executive offices is P.O. Box 2229,
Houston, Texas 77252-2229.

BUSINESS STRATEGY

GEOGRAPHIC FOCUS. The Company concentrates its primary oil and gas
activities in the Gulf Coast region, specifically in state and federal waters
off the coast of Texas and Louisiana. The Company believes this region remains
attractive for future development, exploration and acquisition activities. This
is due to the availability of seismic data, significant reserve potential and a
well developed infrastructure of gathering systems, pipelines and platforms with
ready access to drilling services and equipment in the region. In addition, the
Company's relationships with major oil companies and independent producers
operating in the region allow continued access to new opportunities. This
geographic focus has enabled the Company to build and utilize a base of
region-specific geological, geophysical, engineering and production expertise.
The Company's geographic focus allows it to manage a large asset base with
relatively few employees, thus permitting the Company to control expenses and
add Gulf of Mexico production at a relatively low

44
<PAGE>
incremental cost. The Company engages in IPF Program activities throughout the
onshore regions of the United States, with a principal geographic focus in the
Gulf Coast region.

CERTAIN TRANSACTIONS

ACQUISITION OF COMMON STOCK BY FUND VII. Concurrently with consummation of
the Offering, Fund VII, the Company's principal stockholder, has agreed to
purchase 643,037 shares of Common Stock, at a price per share equal to the Price
to Public set forth on the cover page of this Prospectus, for an aggregate

45
<PAGE>
purchase price of $8,681,000 (the "Concurrent Sale"). See "Transactions with
Management and First Reserve --Acquisition of Common Stock by Fund VII."

THE FUNDS ACQUISITION. The Company previously sponsored and managed two oil
and gas investment programs (collectively, the "Funds") for institutional
investors. The Company has entered into a definitive agreement with the
investors in the Funds to acquire certain property interests from such investors
upon consummation of the Offering (the "Funds Acquisition"). These property
interests are primarily located in the Gulf Coast region and have combined
proved reserves of 33.0 Bcfe. Furthermore, these interests include 18,209 net
undeveloped leasehold acres with 3-D seismic based exploration potential. The
Company will acquire these reserves at an aggregate cost of $30.0 million,
effective January 1, 1997, for a unit cost of $0.65 per Mcfe of net proved
reserves. The Funds Acquisition will provide the Company with a larger interest
in certain of its existing properties, including the West Delta 30 Field in the
Gulf of Mexico.

The Company retained its interests in Oceana Exploration Company, L.C., a
Michigan exploration company. See "Business and Properties -- Exploration
Programs -- Michigan."

DEVELOPMENT, EXPLOITATION AND EXPLORATION PROJECTS

Set forth below is a description of the development and exploitation
projects that the Company's management expects to pursue during calendar year
1997. While the Company presently intends to complete these projects, the
number, type and timing thereof are subject to change as a result of many
factors, including the availability of capital to fund such projects, initial
test results, results of drilling by third parties on adjacent blocks, weather,
oil and gas prices and other general economic conditions that are beyond the
control of the Company. In addition, because the Company does not operate most
of its properties, it can influence but does not have the ability to control the
initiation and timing of many capital projects. The Company currently
anticipates spending approximately $29.0 million during calendar year 1997 on
development and exploration projects, including those described below. There can
be no assurance that any of these projects can be successfully developed within
budget, or that, once developed, such projects will be commercially productive.
See "Risk Factors -- Volatility of Oil and Natural Gas Prices; Marketability of
Production," "-- Reserve Replacement Risks," "-- Reliance on Estimates of Oil
and Natural Gas Reserves" and "-- Substantial Capital Requirements."

46
<PAGE>
MATAGORDA ISLAND 519. In late 1994 the Company purchased 13 producing
fields in the Gulf of Mexico from Pennzoil Company ("Pennzoil") for $51.3
million (the "Pennzoil Acquisition"), including the Matagorda Island 519 Field.
The Company owns working interests of 15.8% and 25% in this field, which is
operated by Amoco Production Company ("Amoco"). Workover operations on two wells
in this field were completed in the first quarter of 1997, increasing gross
production by 10 MMcf per day. Workover operations to recomplete a third well
are in progress. The Company believes that significant development and
exploratory potential remains in the field. Amoco has purchased a 3-D seismic
survey to delineate these opportunities, in which the Company owns a 25% working
interest.

HIGH ISLAND 110/111. The Company purchased its initial interest in this
Texaco-operated field as part of the Pennzoil Acquisition and currently holds a
17% working interest. The Company has identified several recompletion zones and
two proved undeveloped drilling locations in the field using 3-D seismic data to
reinterpret an internal field study. These wells are scheduled to be drilled in
1997.

PRODUCER INVESTMENT ACTIVITIES

IPF PROGRAM. The Company complements its exploration and production
activities with its IPF Program pursuant to which it invests in oil and natural
gas reserves through the acquisition of term overriding royalty interests. From
inception through December 31, 1996, the IPF Program has generated an average
return on assets employed of approximately 19%. The IPF Program was established
in 1993 and is funded by a combination of equity provided by the Company and
third-party debt. The IPF Program enables independent producers to obtain
nonrecourse financing, while maintaining ownership of their properties, through
the sale to the Company of term overriding royalty interests. Transaction sizes
for the program generally have ranged from $0.5 million to $5.0 million. A
strong customer focus has resulted in a large majority of IPF Program customers
having returned for additional funding requests and approximately a 100% average
annual growth in year-end customers over the last two years. From inception
through December 31, 1996, the Company completed 40 transactions under the IPF
Program. At December 31, 1996, based on Company estimates and assuming prices of
$2.10 per Mcf of natural gas and $21.00 per Bbl of oil, the net present value
attributable to IPF Program assets was $25.4 million.

The Company believes that the IPF Program offers a lower level of reserve,
production and price risk than that associated with working interest ownership.
Such risks are mitigated through strict adherence to the Company's IPF Program
underwriting guidelines and the Company structuring its investment to receive an
agreed upon share of revenues from identified properties until a contractual
return is attained. The Company's underwriting guidelines include the
requirement of sufficient reserve value, or collateral coverage, in excess of
the IPF Program investment and the requirement that the IPF Program investments
be structured so as not to bear production expenses. Additionally, because the
Company originates dollar-denominated IPF Program assets, the effect of
commodity price declines on the expected return on these assets is reduced as
compared to working interest ownership. This reduction in price risk occurs
because the Company structures its IPF Program term overriding royalty interests
to result in a contractual return before the overriding royalty interest is
discharged. As a result, IPF Program customers must deliver proceeds from

47
<PAGE>
the sale of oil and gas production until such return is achieved by the Company
on its investment, regardless of the commodity price realized by the customer
over the term of the transaction.

On June 7, 1996, the Company's indirect wholly-owned subsidiary, IPF
Company, entered into the IPF Company Credit Facility pursuant to which it
finances the purchase of term overriding royalty interests under the IPF
Program. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources -- IPF Company Credit
Facility."

THE GASFUND. In May 1993, Ventures Corporation and EnCap Ventures 1993
Limited Partnership ("EnCap") finalized a partnership arrangement named the
GasFund ("GasFund"). The GasFund was a financing vehicle that utilized bank debt
supported by limited Company and EnCap credit enhancements, which provided
production-based financing to independent producers for oil and gas projects
generally exceeding $10.0 million.

Currently, there are no existing obligations and no outstanding
transactions associated with the GasFund. As a result of the Company's
assessment that the market to provide financing in amounts greater than $10.0
million is competitive to the point of unattractive returns, and the reduced
credit enhancement capabilities of the Company as a result of the Acquisition,
the Company does not anticipate participating in any future GasFund
transactions.

EXPLORATION PROGRAMS

During 1996 the Company participated in 33 exploration wells with 20
completions, for a 60.6% success rate. In addition to the exploration that the
Company may conduct on its existing properties, the Company intends to continue
participation in exploration activities through various joint venture programs,
including those summarized below.

SOUTH TEXAS -- COX & PERKINS DRILLING PROGRAM. The Cox & Perkins drilling
program is an exploration effort in the expanded Yegua gas trend within Jackson
and Wharton Counties, Texas. The Company holds a 10% working interest in this
program, which utilizes 3-D seismic data to delineate potential structural and
stratigraphic traps within the trend. The program sponsor and operator is Cox &
Perkins Exploration, Inc., a privately-held, independent exploration and
production company. Thirty-one wells have been drilled to date, of which 21 are
productive. Current gross daily production from the wells is approximately 41
MMcf of natural gas and 1,181 Bbls of condensate. One additional development
well is scheduled to be drilled in 1997.

SOUTH TEXAS -- KENEDY RANCH. The Kenedy Ranch program is an exploration
effort to delineate expanded Frio reservoir traps on this large ranch in Kenedy
County along the southern Texas Gulf Coast. Output Exploration Company, Inc.,
Hunt Petroleum Company and the Company have shot a 180 square mile 3-D seismic
survey and acquired 49,000 acres in defining potential drill sites. The program
operator is Hunt Petroleum Company. Interpretation of the seismic data has
identified five primary prospect areas. The first well drilled was a dry hole
and a second well is currently being drilled. The Company holds a 12.5% working
interest in this project.

SOUTH LOUISIANA SALT DOMES. The Company and an affiliate of Shell, together
with the operator, Texaco, are engaged in an effort to delineate the
exploitation and exploration potential of three salt domes in southern
Louisiana, including the Rabbit Island Field. The group is utilizing 3-D seismic
to identify remaining potential. Ten out of 12 wells drilled to date have been
successful, discovering approximately 63.2 Bcfe of gross proved reserves (12.0
Bcfe net to the Company's interest). The Company's net working interest in these
program wells ranges from 7.6% to 25%.

ANADARKO BASIN. The Anadarko Basin seismic program is an exploration
effort within the Morrow Sand trend. The Company and the operator, Brigham
Exploration Company, are utilizing 3-D seismic technology to delineate potential
gas reservoirs in the channel-controlled Upper Morrow Sand. Additional
objectives are present both above and below the main objective. The program
participants hold 35,750 gross acres under lease. Six 3-D seismic surveys have
been shot and the evaluation thereof is in progress. Eight wells have been
drilled to date, of which two are producing and two are nearing completion. The
Company

48
<PAGE>
holds a 70% working interest in two of the 3-D areas, a 37.5% working interest
in three of the 3-D areas and a 35% working interest in the remainder. Three
additional wells are currently being drilled or are scheduled to be drilled in
the first half of 1997.

PERMIAN BASIN. The Permian Basin drilling program is an exploration effort
targeting the Wolfcamp and Strawn Formations. The Company and the operator, Rand
Paulson Oil Company, Inc., a privately-held, independent exploration and
production company, combine 3-D seismic technology with detailed,
biostratigraphic zonation work to delineate potential traps. Numerous secondary
objectives exist above the primary targets. The program participants hold 32,400
gross acres under lease. To date, the Company has participated in 15 wells, of
which five were productive and three are currently being drilled. Eleven
additional leads and prospects are being evaluated for future drilling
opportunities. The Company holds a 50% working interest in the program.

MICHIGAN. Oceana Exploration Company, L.C., a Texas limited liability
company and 80% owned subsidiary of Ventures Corporation, is obligated to drill,
or cause to be drilled, four exploratory wells in Oceana County, Michigan by the
end of 1997. Two such wells have been drilled and are awaiting completion.
Through this program, the Company is targeting the Niagaran reef trend, which
the Company believes has significant exploratory potential.

SIGNIFICANT PROPERTIES

The following table sets forth the net proved reserves and the PV-10
Reserve Value attributable to the Company's significant properties as of
December 31, 1996 and on a pro forma basis as of December 31, 1996 after giving
effect to the Funds Acquisition and the Michigan Disposition. The reserve data
set forth below does not include reserves or reserve value attributable to the
IPF Program. At December 31, 1996, the Company estimates that the net present
value attributable to IPF Program assets was $25.4 million.

<TABLE>
<CAPTION>
PRO FORMA
AS OF DECEMBER 31, 1996 AS OF DECEMBER 31, 1996
------------------------------------- -------------------------------------
NET % OF TOTAL PV-10 NET % OF TOTAL PV-10
PROVED NET RESERVE PROVED NET RESERVE
RESERVES PROVED VALUE RESERVES PROVED VALUE
(BCFE) RESERVES (IN MILLIONS) (BCFE) RESERVES (IN MILLIONS)
-------- ---------- ------------- -------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
GULF COAST FIELDS
Matagorda Island 519............... 14.2 9.5% $ 33.6 14.2 9.2% $ 33.6
West Delta 30...................... 11.5 7.7% 18.4 28.8 18.7% 46.1
High Island 110/111................ 5.6 3.7% 8.4 5.6 3.6% 8.4
Eugene Island 372.................. 3.0 2.0% 4.7 3.0 2.0% 4.7
Rabbit Island...................... 3.0 2.0% 10.3 3.0 2.0% 10.3
Main Pass 74....................... 2.5 1.7% 4.7 2.5 1.6% 4.7
Other Gulf Coast................... 30.7 20.6% 61.8 46.4 30.2% 99.8
-------- ---------- ------------- -------- ---------- -------------
70.5 47.2% $ 141.9 103.5 67.3% $ 207.6
OTHER FIELDS
Wasson Field....................... 50.3 33.6% $ 12.6 50.3 32.7% $ 12.6
Michigan Development Project....... 28.8 19.2% $ 36.9 -- -- --
-------- ---------- ------------- -------- ---------- -------------
Total......................... 149.6 100% $ 191.4(1) 153.8 100% $ 220.2(1)
======== ========== ============= ======== ========== =============
</TABLE>
- ------------

(1) Does not reflect losses calculated to be incurred from future hedging
activities. As a result of such losses, PV-10 Reserve Value and pro forma
PV-10 Reserve Value as of December 31, 1996 were $184.8 million and $213.0
million, respectively.

MATAGORDA ISLAND 519 FIELD. The Matagorda Island Block 519 Field is located
offshore Texas, approximately 12 miles southeast of Matagorda County, in
approximately 69 feet of water. Amoco discovered the field in 1983 and is the
current operator. Four wells produce gas from lower Miocene Sands at a depth of
approximately 14,800 feet to 17,000 feet. This field is currently producing 59.1
MMcf of gas

49
<PAGE>
per day and 157 Bbls of oil per day (7.7 MMcf and 7.4 Bbls net to the Company's
interest). The Company acquired an average 20% working interest in the field
effective October 1, 1994 pursuant to the Pennzoil Acquisition.

WEST DELTA 30 FIELD. The West Delta 30 Field is located offshore Louisiana,
approximately 65 miles south-southeast of New Orleans, in approximately 50 feet
of water. The field was discovered in 1954 and has had over 200 wells drilled,
the last of which was drilled in the early 1990s. Effective January 1, 1995, the
Company acquired 70% of Shell's working interests in this field, which ranged
from 50% to 100%. Cumulative production to date is approximately 300 Bcf of gas
and 200 MMBbls of oil and the field currently produces 5.9 MMcf of gas per day
and 1,551 Bbls of oil per day (1.65 MMcf and 434 Bbls net to the Company's
interest). Seneca Resources Corporation and Exxon are the operators of the
field. The West Delta 30 Field produces from Pliocene and Miocene Sands at a
depth of approximately 6,500 feet to 11,000 feet that are trapped against a salt
dome feature.

HIGH ISLAND 110/111 FIELD. High Island Blocks 110 and 111 are located
offshore Texas, approximately 20 miles offshore of Jefferson County, in
approximately 30 feet of water. The field was discovered in 1973 and is
currently operated by Texaco. The 17.7% average working interest owned by the
Company was acquired from Pennzoil in 1994 and Sonat Exploration Company in
1996. Cumulative production to date from this field has been approximately 309
Bcf of gas and 2.6 MMBbls of oil and the field currently produces 9.5 MMcf of
gas per day and 173 Bbls of oil per day (1.4 MMcf and 24.6 Bbls net to the
Company's interest). The High Island 110/111 Field produces from Miocene Sands
at a depth of approximately 7,500 feet to 12,500 feet that are trapped in a
faulted anticline, downthrown to a major listric fault.

EUGENE ISLAND 372 FIELD. Eugene Island Block 372 is located offshore
Louisiana, approximately 168 miles southwest of New Orleans, in approximately
400 feet of water. This field was discovered in 1978 and has produced
approximately 44 Bcf of gas and 1.5 MMBbls of oil from nine wells. Currently,
there are five active wells in this field. The Company acquired its 37.5%
working interest in this field as a result of the Pennzoil Acquisition. The
Eugene Island 372 Field produces from Pleistocene Sands at a depth of
approximately 5,100 feet to 9,900 feet. The reservoir trap is characterized by
complex faulting and highly stratigraphic sands. Unocal Corporation ("Unocal"),
the current operator, is in the process of interpreting a new 3-D seismic survey
covering the block and has identified several untested seismic amplitudes. Work
is in progress to evaluate the size and economic viability of these leads.

RABBIT ISLAND. The Rabbit Island Field is located in Louisiana state
waters, approximately 95 miles southwest of New Orleans in approximately ten
feet of water. This field was discovered in 1939 and has produced in excess of
1.2 Tcf of gas and 46 MMBbls of oil. The field is currently producing 27.4 MMcf
of gas per day and 48 Bbls of oil per day (5.4 MMcf and 9.0 Bbls net to the
Company's interest). Benton Oil & Gas Company of Louisiana ("Benton") earned a
50% working interest in this field from Texaco by acquiring and interpreting a
105 square mile 3-D seismic survey across the field. In 1993, the Company bought
a 25% working interest from Benton. In early 1996, Shell acquired Benton,
leaving Texaco, Shell, and the Company as working interest owners. The
productive interval is Miocene Sands at a depth of approximately 1,600 feet to
12,000 feet. The field is a piercement salt dome with associated radial
faulting.

MAIN PASS 74. Main Pass Block 74 is located in Louisiana state waters,
approximately 85 miles southeast of New Orleans in approximately 75 feet of
water. This field was discovered in 1981 and is currently operated by Exxon.
Cumulative production from this field has been approximately 20 MMBbls of oil
and 41 Bcf of gas. The Company acquired an average working interest of 14.4% in
this field as a result of the Pennzoil Acquisition. All production from the Main
Pass 74 Field has come from Miocene Puma Sand at a depth of approximately 10,000
feet to 10,500 feet. The reservoir trap is a westerly-dipping, stratigraphic
trap. The Company has identified one additional drilling location within the
field, and Exxon has expressed an interest in drilling a horizontal well into
the reservoir.

WASSON FIELD. The Wasson Field is located in Gaines and Yoakum Counties,
Texas, approximately 80 miles northwest of Midland, Texas. In June 1996 the
Company acquired from Kerr-McGee Corporation 34.7% and .17% working interests in
the Cornell and Denver Units at this field, respectively. These two

50
<PAGE>
units are currently producing 41,469 Bbls of oil per day (539 Bbls net to the
Company's interest). The Wasson Field was discovered in 1937. The Cornell and
Denver Units are currently operated by Exxon and Altura Energy, Inc. (a joint
venture between Shell and Amoco), respectively. Approximately 1.5 billion
barrels of oil have been produced from the San Andres reservoir. The San Andres
produces in both the Cornell and Denver Units at depths of approximately 5,500
feet to 6,000 feet. This field was initially waterflooded in 1965, and a CO2
flood was initiated in 1985 utilizing the water-alternating-gas injection method
of enhanced oil recovery.

OIL AND NATURAL GAS RESERVES

The following table summarizes the estimates of the Company's historical
net proved reserves as of December 31, 1994, 1995 and 1996 and pro forma net
proved reserves as of December 31, 1996, and the present values attributable to
these reserves at such dates. The reserve data and present values as of December
31, 1994 have been estimated by DeGolyer and other third-party petroleum
engineers. The reserve data and present values as of December 31, 1995 have been
estimated by DeGolyer and Netherland, Sewell. The reserve data and present
values as of December 31, 1996 have been estimated by (i) Netherland, Sewell,
with respect to the West Delta 30 Field, (ii) by other third-party petroleum
engineers with respect to the Michigan Development Project and (iii) by DeGolyer
with respect to all of the Company's other oil and natural gas properties. See
"Significant Properties." The pro forma December 31, 1996 reserve data and
present values give effect to the Funds Acquisition and the Michigan
Disposition. Summaries of the December 31, 1996 reserve reports and the letters
of DeGolyer and Netherland, Sewell with respect thereto are included as Appendix
A to this Prospectus. The reserve data set forth below does not include reserves
or reserve value attributable to the IPF Program. At December 31, 1996, the
Company estimates that the net present value attributable to IPF Program assets
was $25.4 million.

AS OF DECEMBER 31,
--------------------------------------------
PRO FORMA
1994 1995 1996(1)(2) 1996(1)
--------- ---------- ---------- ---------
PROVED RESERVES:
Natural Gas (MMcf)............... 73,399 82,682 81,338 83,418
Oil and condensate (MBbls)....... 4,109 2,197 11,380 11,736
Total (MMcfe).................... 98,056 95,865 149,616 153,834

PROVED DEVELOPED PRODUCING RESERVES :
Natural Gas (MMcf)............... 46,544 45,386 36,293 44,292
Oil and condensate (MBbls)....... 967 1,219 9,248 9,673
Total (MMcfe).................... 52,346 52,700 91,781 102,330

PV-10 Reserve Value
(in thousands).................. $61,812 $ 103,931 $ 184,816 $ 213,030
Standardized measure of discounted
future net cash flows (in
thousands)...................... $68,492 $ 98,999 $ 154,424 --
- ------------

(1) The present values as of December 31, 1996 were prepared using a weighted
average sales price of $22.50 per Bbl of oil and $3.38 per Mcf of natural
gas. The pro forma present values as of December 31, 1996 were prepared
using a weighted average sales price of $23.63 per Bbl of oil and $3.59 per
Mcf of natural gas. By comparison, the present values as of December 31,
1995 were prepared using a weighted average sales price of $18.76 per Bbl of
oil and $3.30 per Mcf of natural gas.

(2) Includes the Company's proportionate share of reserves attributable to the
Michigan Development Project.

The estimation of reserve data is a subjective process of estimating the
recovery of underground accumulations of oil and natural gas that cannot be
measured in an exact manner, and the accuracy of any reserve estimate is a
function of the quality of the available data, the assumptions made, and
engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and natural gas reserves and future net cash flows
therefrom necessarily depend upon a number of variable factors and

51
<PAGE>
assumptions, including historical production from the area compared with
production from other producing areas, the assumed effects of regulation by
governmental agencies and assumptions concerning future oil and natural gas
prices, future operating costs, severance and excise taxes, development costs
and workover and remedial costs, all of which may in fact vary considerably from
actual results. Any such estimates are therefore inherently imprecise, and
estimates by other engineers, or by the same engineers at a different time,
might differ materially from those included herein. Actual prices, production,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves will vary from those assumed in the estimates and it is
likely that such variances will be significant. Any significant variance from
the assumptions could result in the actual quantity of the Company's reserves
and future net cash flow therefrom being materially different from the estimates
set forth in this Prospectus. In addition, the Company's estimated reserves may
be subject to downward or upward revision, based upon production history,
results of future exploration and development, prevailing oil and natural gas
prices, operating and development costs and other factors.

Estimates with respect to proved undeveloped reserves that may be developed
and produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be substantial, in the
estimated reserves.

The present value of future net cash flows shown above should not be
construed as the current market value, or the market value as of December 31,
1996, or any prior date, of the estimated oil and natural gas reserves
attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from estimated proved reserves are based on prices and costs as of the date of
the estimate unless such prices or costs are contractually determined at such
date. Actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as actual
production, supply and demand for oil and natural gas, curtailments or increases
in consumption by natural gas purchasers, changes in governmental regulations or
taxation and the impact of inflation on costs.

The Company's PV-10 Reserve Value as of December 31, 1996 was prepared
using a weighted average sales price of $22.50 per Bbl of oil and $3.38 per Mcf
of natural gas. These prices were substantially higher than prices used by the
Company to calculate PV-10 Reserve Value in recent years. The Company estimates
that a substantial decline in prices relative to year-end 1996 would cause a
substantial decline in the Company's PV-10 Reserve Value. For example, compared
to the pro forma data set forth in the above table as of December 31, 1996, a
$0.10 per Mcf decline in natural gas prices, holding all other variables
constant, would decrease the Company's pro forma December 31, 1996 PV-10 Reserve
Value by approximately $6.4 million, or 2.8%, and a $1.00 per Bbl decline in oil
and condensate prices would decrease the Company's PV-10 Reserve Value by
approximately $4.0 million, or 1.8%. While the foregoing calculations should
assist the reader in understanding the effect of a decline in oil or natural gas
prices on the Company's PV-10 Reserve Value, such calculations assume that
quantities of recoverable reserves are constant and therefore would not be
accurate if prices decreased to a level at which reserves would no longer be
economically recoverable.

In accordance with methodology approved by the Commission, specific
assumptions were applied in the estimates of future net cash flows. Under this
methodology, estimated future net cash flows are determined by reducing
estimated future gross cash flows to the Company for oil and natural gas sales
by the estimated costs to develop and produce the underlying reserves, including
future capital expenditures, operating costs, transportation costs, royalty and
overriding royalty burdens. Estimated future production costs were based on
actual annual production costs incurred during the reported period. A portion of
the Company's proved reserves are undeveloped, and future development costs
thereon were calculated based on a continuation of present economic conditions.

Future net cash flows were discounted at 10% per annum to arrive at
discounted future net cash flows. The 10% discount factor used to calculate
present value is required by the Commission, but such rate is not

52
<PAGE>
necessarily the most appropriate discount rate. Present value of future net cash
flows, irrespective of the discount rate used, is materially affected by
assumptions as to timing of future natural gas and oil prices and production,
which may prove to be inaccurate. In addition, the calculations of estimated net
revenues do not take into account the effect of certain cash outlays, including
among other things, general and administrative costs, interest expense and
dividends.

The Company's estimated proved reserves have not been filed with or
included in reports to any federal authority or agency.

PRODUCTION, PRICES AND OPERATING EXPENSES
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------- ------------------------
PREDECESSOR PREDECESSOR SUCCESSOR
------------------------------- ----------- ---------
1994 1995 1996 1996 1997
--------- --------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Natural gas (MMcf)................. 2,334 18,065 21,192 5,828 3,668
Oil and liquids (MBbls)............ 83 424 564 116 141
Total (MMcfe)...................... 2,832 20,609 24,575 6,524 4,516

AVERAGE REALIZED PRICES:(1)
Natural gas (per Mcf).............. $ 1.76 $ 1.54 $ 1.97 $ 2.36 $ 2.75
Oil and liquids (per Bbl).......... 14.93 16.76 18.63 16.52 19.06

EXPENSES (PER MCFE):
Lease operating expense............ $ 0.63 $ 0.39 $ 0.42 $ 0.33 $ 0.68
Production taxes................... 0.01 0.03 0.05 0.04 0.09
Depreciation, depletion and
amortization..................... 1.03 1.08 1.01 1.19 0.69
General and administrative,
net(2)........................... 0.26 0.16 0.12 0.14 0.14
</TABLE>
- ------------

(1) Reflects the actual realized prices received by the Company, including the
results of the Company's hedging activities. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Other
Matters -- Hedging Activities."

(2) Includes production attributable to properties managed for the Funds for the
periods indicated and excludes fees received from investors and overhead
allocations from Tenneco. Including Tenneco allocations, average net general
and administrative expenses per Mcfe for the years ended December 31, 1994,
1995, and 1996 would be $0.26, $0.20 and $0.28, respectively.

53
<PAGE>
PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which the Company owned an interest as of March 31, 1997.

TOTAL PRODUCTIVE
WELLS
--------------------
GROSS NET
--------- ---------
OFFSHORE
Natural gas............................. 67.0 18.9
Oil..................................... 35.0 7.4
--------- ---------
Total.............................. 102.0 26.3

ONSHORE
Natural gas............................. 43.0 10.0
Oil..................................... 838.0(1) 25.6(1)
--------- ---------
Total.............................. 881.0 35.6

TOTAL OFFSHORE AND ONSHORE
Natural gas............................. 110.0 28.9
Oil..................................... 873.0(1) 33.0(1)
--------- ---------
Total.............................. 983.0 61.9
========= =========
- ------------

(1) Includes 756 gross wells in the Wasson Field (Denver Unit) in which the
Company holds a 0.17% working interest.

Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections to
commence deliveries and oil wells awaiting connection to production facilities.
In wells with multiple completions mechanically isolated zones are counted as
individual wells.

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<PAGE>
ACREAGE DATA

The following table sets forth the approximate developed and undeveloped
acreage in which the Company held a leasehold mineral or other interest as of
March 31, 1997. 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 natural gas, regardless of whether or not such
acreage contains proved reserves.

TOTAL ACREAGE DEVELOPED UNDEVELOPED
-------------------- ACREAGE ACREAGE
AREA (GROSS) (NET) (NET) (NET)
- ------------------------------ --------- --------- --------- -----------
Onshore:
Alabama.................. 18,571 2,889 2,889 --
Louisiana................ 9,630 3,843 1,058 2,785
Michigan................. 10,419 9,058 1,512 7,546
Mississippi.............. 4,292 953 626 327
New Mexico............... 32,203 12,750 168 12,582
Texas.................... 102,837 16,464 2,493 13,971
--------- --------- --------- -----------
Total Onshore................. 177,952 45,957 8,746 37,211
--------- --------- --------- -----------
Offshore:
Louisiana................ 158,776 42,283 29,333 12,950
Texas.................... 74,795 23,512 20,392 3,120
--------- --------- --------- -----------
Total Offshore................ 233,571 65,795 49,725 16,070
--------- --------- --------- -----------
Total......................... 411,523 111,752 58,471 53,281
========= ========= ========= ===========

The Company will acquire an aggregate of 15,062 developed and 18,209
undeveloped net leasehold acres pursuant to the Funds Acquisition and has
disposed of 1,892 of the gross leasehold acres and 1,512 of the net developed
leasehold acres set forth above in Michigan pursuant to the Michigan
Disposition.

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<PAGE>
DRILLING ACTIVITIES

The following table sets forth the drilling activity of the Company on its
properties for the years ended December 31, 1994, 1995 and 1996 and the three
months ended March 31, 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------- THREE MONTHS
ENDED
1994 1995 1996 MARCH 31, 1997
------------- ------------- ------------- --------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
OFFSHORE DRILLING ACTIVITY:
Development:
Productive...................... 3.0 0.8 2.0 0.5 5.0 1.5 -- --
Non-productive.................. -- -- -- -- -- -- -- --
----- --- ----- --- ----- ---
Total...................... 3.0 0.8 2.0 0.5 5.0 1.5 -- --
Exploratory:
Productive...................... 2.0 0.9 4.0 1.3 2.0 0.6 -- --
Non-productive.................. 4.0 0.5 4.0 0.9 1.0 0.2 -- --
----- --- ----- --- ----- ---
Total...................... 6.0 1.4 8.0 2.2 3.0 0.8 -- --

ONSHORE DRILLING ACTIVITY:
Development:
Productive...................... -- -- 4.0 0.7 2.0 0.3 -- --
Non-productive.................. -- -- 1.0 0.1 2.0 0.6 -- --
----- --- ----- --- ----- ---
Total...................... -- -- 5.0 0.8 4.0 0.9 -- --
Exploratory:
Productive...................... 12.0 1.7 15.0 1.8 18.0 2.0 4.0 1.0
Non-productive.................. 14.0 2.7 25.0 4.6 12.0 1.7 5.0 1.3
----- --- ----- --- ----- --- ----- ---
Total...................... 26.0 4.4 40.0 6.4 30.0 3.7 9.0 2.3
</TABLE>
The information contained in the foregoing table should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled and
the oil and natural gas reserves generated therefrom.

From January 1, 1997 through May 15, 1997, the Company participated in
drilling activities on 23 gross wells. Of the 23 (7.6 net) wells, 10 (3.4 net)
are being completed, or have been completed, as commercial producers, 6 (1.6
net) were dry holes, and 7 (2.6 net) are currently being drilled.

OIL AND GAS MARKETING

The Company's production is priced based on short-term spot prices and is
marketed to third parties consistent with industry practices. The Company is
aided by the presence of multiple delivery points near its production in the
Gulf Coast region. From time to time, the Company has hedged a portion of its
oil and gas production to achieve more predictable cash flows and to reduce its
exposure to fluctuations in oil and gas prices. Despite the measures taken by
the Company to attempt to control price risk, the revenues generated by the
Company's operations are highly dependent upon the prices of, and demand for,
oil and natural gas. The price received by the Company for its oil and natural
gas production depends on numerous factors beyond the Company's control,
including seasonality, the condition of the United States economy (particularly
the manufacturing sector), foreign imports, political conditions in other
natural gas-producing and oil-producing countries, the actions of OPEC and
domestic government regulation, legislation and policies. Decreases in the
prices of oil and natural gas could have a material adverse effect on the
carrying value of the Company's proved reserves and the Company's revenues,
profitability and cash flow. Although the Company is not currently experiencing
any significant involuntary curtailment of its oil or natural gas production,
market, transportation, economic and regulatory factors may in the future
materially adversely affect the Company's ability to sell its oil or natural gas
production. See "Risk Factors -- Volatility of Oil

56
<PAGE>
and Natural Gas Prices; Marketability of Production" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

COMPETITION

The Company encounters competition from other companies in all areas of its
operations, including the acquisition of producing properties and its IPF
Program. The Company's competitors include major integrated oil and gas
companies and numerous independent oil and gas companies, individuals and
drilling and income programs and, in the case of its IPF Program, affiliates of
investment, commercial and merchant banking firms and affiliates of large
interstate pipeline companies. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Company's and which, in many instances, have
been engaged in the oil and gas business for a much longer time than the
Company. Such companies may be able to pay more for productive natural gas and
oil properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future, and to grow its IPF Program,
will be dependent upon its ability to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment.

REGULATION

The availability of a ready market for oil and natural gas production
depends upon numerous factors beyond the Company's control. These factors
include regulation of oil and natural gas production, federal, state and local
laws and regulations governing environmental quality and pollution control,
state limits on allowable rates of production by a well or proration unit, the
supply of oil and natural gas available for sale, the availability of adequate
pipeline and other transportation and processing facilities and the marketing of
competitive fuels. For example, a productive natural gas well may be "shut-in"
because of an oversupply of natural gas or the lack of an available natural gas
pipeline in the areas in which the Company conducts its operations. Federal,
state and local laws and regulations generally are intended to prevent waste of
oil and natural gas, protect rights to produce oil and natural gas between
owners in a common reservoir, control the amount of oil and natural gas produced
by assigning allowable rates of production and control contamination of the
environment.

REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION. The Company's
exploration and production operations are subject to various types of regulation
at the federal, state and local levels. Such regulation includes requiring
permits for the drilling of wells, maintaining bonding requirements 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 drilling and the plugging and abandonment of wells. The
Company's operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and spacing
units or proration units and the density of wells that may be drilled and
unitization or pooling of oil and gas properties. In this regard, some states
allow the forced pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of lands and leases. In addition,
state conservation laws establish maximum rates of production from oil and
natural gas wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production. The effect
of these regulations is to limit the amounts of oil and natural gas the
Company's operator or the Company can produce from its wells, and to limit the
number of wells the Company can drill or the locations thereof. In addition,
numerous departments and agencies, both federal and state, are authorized by
statute to issue rules and regulations binding on the oil and gas industry and
its individual members, some of which carry substantial penalties for failure to
comply. The regulatory burden on the oil and gas industry increases the
Company's cost of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.

57
<PAGE>
NATURAL GAS MARKETING AND TRANSPORTATION. Federal legislation and
regulatory controls in the United States have historically affected the price of
the natural gas produced by the Company and the manner in which such production
is marketed. The transportation and sale for resale of natural gas in interstate
commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the
Natural Gas Policy Act of 1978 (the "NGPA") and the Federal Energy Regulatory
Commission (the "FERC"). Although maximum selling prices of natural gas were
regulated in the past, on July 26, 1989, the Natural Gas Wellhead Decontrol Act
of 1989 ("Decontrol Act") was enacted, which amended the NGPA to remove
completely by January 1, 1993 price and nonprice controls for all "first sales"
of domestic natural gas, which include all sales by the Company of its
production; consequently, sales of the Company's natural gas production
currently may be made at market prices, subject to applicable contract
provisions. The FERC's jurisdiction over natural gas transportation was
unaffected by the Decontrol Act.

The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to natural gas buyers and
sellers on an open and nondiscriminatory basis. The FERC's efforts have
significantly altered the marketing and pricing of natural gas. Commencing in
April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C
(collectively, "Order No. 636"), which, among other things, require interstate
pipelines to "restructure" to provide transportation separate or "unbundled"
from the pipelines' sales of natural gas. Also, Order No. 636 requires pipelines
to provide open-access transportation on a basis that is equal for all natural
gas supplies. Order No. 636 has been implemented through negotiated settlements
in individual pipeline service restructuring proceedings. In many instances, the
result of the Order No. 636 and related initiatives has been to reduce
substantially or bring to an end the interstate pipelines' traditional role as
wholesalers of natural gas in favor of providing only storage and transportation
services. The FERC has issued final orders in virtually all pipeline
restructuring proceedings, and has now commenced a series of one year reviews to
determine whether refinements are required regarding individual pipeline
implementations of Order No. 636.

In May 1995, the FERC issued a policy statement on how interstate gas
pipelines can recover the costs of new pipeline facilities. While this policy
statement affects the Company only indirectly, in its present form the new
policy should enhance competition in natural gas markets and facilitate
construction of gas supply laterals. However, requests for rehearing of this
policy statement are currently pending. The Company cannot predict what action
the FERC will take on these requests.

Commencing in May 1994, the FERC issued a series of orders in individual
cases that delineate a new gathering policy in light of the interstate pipeline
industry's restructuring under Order No. 636. As a general matter, gathering is
exempt from the FERC's jurisdiction; however, the courts have held that 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. Among other
matters, the FERC slightly narrowed its statutory tests for establishing
gathering status and reaffirmed that, 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 over
natural gas gathering facilities and services. In the FERC's opinion, such
facilities and services are more properly regulated by state authorities. In
addition, the FERC has approved several transfers proposed by interstate
pipelines of gathering facilities to unregulated independent or affiliated
gathering companies. Certain of the FERC's orders delineating its new gathering
policy recently were the subject of an opinion issued by the United States Court
of Appeals for the District of Columbia Circuit. That opinion generally upheld
the FERC's policy of approving the interstate pipeline's proposed "spindown" of
its gathering facilities to an unregulated affiliate company, but remanded to
the FERC that portion of the FERC's orders imposing so-called "default
contracts" by which the unregulated affiliate was obligated to continue existing
gathering services to customers 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. In

58
<PAGE>
addition, in February 1996, the FERC issued a policy statement that, among other
matters, reaffirmed, with some clarifications, its long-standing test for
determining whether particular pipeline facilities perform a jurisdictional
transmission function or nonjurisdictional gathering function. While changes to
the FERC's 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.

Proposals and proceedings that might affect the natural gas industry are
considered from time to time by Congress, the FERC, state regulatory bodies and
the courts. The Company cannot predict when or if any such proposals might
become effective, or their effect, if any, on the Company's operations. The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue indefinitely into the future.

FEDERAL OFFSHORE LEASING. Certain of the Company's operations are conducted
on federal oil and gas leases administered by the Minerals Management Service
("MMS"). The MMS issues such leases through competitive bidding. These leases
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency), lessees must obtain a permit
from the MMS prior to the commencement of drilling. The MMS has promulgated
regulations requiring offshore production facilities located on the Outer
Continental Shelf ("OCS") to meet stringent engineering and construction
specifications. The MMS also has issued regulations restricting the flaring or
venting of natural gas and prohibiting the flaring of liquid hydrocarbons and
oil without prior authorization. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities. To cover the various obligations of
lessees on the OCS, the MMS generally requires that lessees post substantial
bonds or other acceptable assurances that such obligations will be met. The cost
of such bonds or other security can be substantial and there is no assurance
that the Company can obtain bonds or other security in all cases. See " --
Environmental Matters."

The OCSLA requires that all pipelines operating on or across the OCS
provide open-access, non-discriminatory service. Although the FERC has opted not
to impose the regulations of Order No. 509, which implements these requirements
of the OCSLA, on gatherers and other non-jurisdictional entities, the FERC has
retained the authority to exercise jurisdiction over those entities if necessary
to permit non-discriminatory access to services on the OCS. If the FERC were to
apply Order No. 509 to gatherers in the OCS, eliminate the exemption of
gathering lines, and redefine its jurisdiction over gathering lines, the result
would be a reduction in available pipeline space for existing shippers in the
Gulf of Mexico and elsewhere.

OIL SALES AND TRANSPORTATION RATES. Sales of crude oil, condensate and gas
liquids by the Company are not regulated and are made at market prices. The
price the Company receives from the sale of these products is affected by the
cost of transporting the products to market. Effective as of January 1, 1995,
the FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, subject to certain conditions and
limitations, would generally index such rates to inflation. The Company is not
able to predict with certainty what effect, if any, these regulations will have
on it, but other factors being equal, under certain conditions the regulations
may cause increased transportation costs and may reduce wellhead prices for such
commodities.

ENVIRONMENTAL MATTERS

The Company's operations are subject to federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types,

59
<PAGE>
quantities and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas, require remedial measures to prevent pollution from
former operations, such as pit closure and plugging abandoned wells, and impose
substantial liabilities for pollution resulting from the Company's operations.
In addition, these laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist. The regulatory
burden on the oil and gas industry increases the cost of doing business and
consequently affects its profitability. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent and
costly waste handling, disposal and clean-up requirements could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general. Management believes that the Company is in substantial
compliance with current applicable environmental laws and regulations and that
continued compliance with existing requirements will not have a material adverse
impact on the Company.

The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances. Under CERCLA, such
persons may be subject to joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment
(including pre-remedial investigations and post-remedial monitoring), for
damages to natural resources. In some instances, neighboring landowners and
other third parties file claims based on common law theories of tort liability
for personal injury and property damage allegedly caused by the release of
hazardous substances at a CERCLA site.

The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of requirements on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in "waters of
the United States." A "responsible party" includes the owner or operator of a
facility or vessel, or the lessee or permittee of the area in which an offshore
facility is located. The term "waters of the United States" has been broadly
defined to include not only the waters of the Gulf of Mexico but also inland
waterbodies, including wetlands, playa lakes and intermittent streams. A 1996
amendment to the OPA also requires owners and operators of "offshore facilities"
(including those located in coastal inland waters, such as bays or estuaries) to
establish $35.0 million in financial responsibility to cover environmental
cleanup and restoration costs likely to be incurred in connection with an oil
spill. Offshore facilities are facilities used for exploring for, drilling for
or producing oil or transporting oil from facilities engaged in oil exploration,
drilling or production. If it is determined that an increase in the amount of
financial responsibility required is warranted, the President has the authority
to raise such to an amount not exceeding $150.0 million. In any event, the
impact of any adjustment to the annual required financial responsibility is not
expected to be any more burdensome to the Company than it will be to other
similarly situated companies involved in oil and gas exploration and production.

OPA imposes a variety of additional requirements on responsible parties for
vessels or oil and gas facilities related to the prevention of oil spills and
liability for damages resulting from such spills in waters of the United States.
OPA assigns liability to each responsible party for oil spill removal costs and
a variety of public and private damages from oil spills. OPA establishes a
liability limit for offshore facilities of all removal costs plus $75.0 million.
A party cannot take advantage of liability limits if the spill is caused by
gross negligence or willful misconduct or resulted from violation of a federal
safety, construction or operating regulation. If a party fails to report a spill
or to cooperate fully in the cleanup, liability limits likewise do not apply.
Few defenses exist to the liability for oil spills imposed by OPA. OPA also
imposes other requirements on facility operators, such as the preparation of an
oil spill contingency plan. Failure to comply with ongoing requirements or
inadequate cooperation in a spill event may subject a responsible party to civil
or criminal enforcement actions. As of the date hereof, the Company is not the
subject of any civil or criminal enforcement actions under the OPA and is in
substantial compliance with the requirements of the OPA.

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<PAGE>
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating in the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or private prosecution. As of the date hereof, the Company
is not the subject of any civil or criminal enforcement actions under the OCSLA
and is in substantial compliance with the requirements under the OCSLA.

The Clean Water Act ("CWA") imposes restrictions and strict controls
regarding the discharge of produced waters and other oil and gas wastes into
navigable waters. Permits must be obtained to discharge pollutants into state
and federal waters. The CWA provides for civil, criminal and administrative
penalties for any unauthorized discharges of oil and other hazardous substances
in reportable quantities and, along with the OPA, imposes substantial potential
liability for the costs of removal, remediation and damages. State laws for the
control of water pollution also provide civil, criminal and administrative
penalties and liabilities in the case of a discharge of petroleum or its
derivatives into state waters. The U.S. Environmental Protection Agency ("EPA")
issued general permits prohibiting the discharge of produced water and produced
sand derived from oil and gas point source facilities into coastal waters in
Louisiana and Texas, which became effective as of January 1, 1997. Although the
costs of compliance with zero discharge mandates under federal or state law may
be significant, the entire industry will experience similar costs and the
Company believes that these costs will not have a material adverse impact on the
Company's financial condition and operations. Certain oil and gas exploration
and production facilities are required to obtain permits for their storm water
discharges and costs may be associated with treatment of wastewater, or
developing storm water pollution prevention plans. In addition, the Coastal Zone
Management Act authorizes state implementation and development of management
measures for nonpoint source pollution designed to restore and protect coastal
waters.

OPERATING HAZARDS AND DRILLING RISKS

The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases. Any of these occurrences could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Moreover, 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, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to interruption
or termination of operations by governmental authorities based on environmental
or other considerations. The presence of unanticipated pressure or
irregularities in formations, miscalculations or accidents may cause such
activity to be unsuccessful, resulting in a total loss of the Company's
investment in such activity. 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 the high premium costs. The Company does not carry business
interruption insurance. There can be no assurance that any insurance obtained by
the Company will be adequate to cover any losses or liabilities, or that such
insurance will continue to be available or available on terms which are
acceptable to the Company. See "Risk Factors -- Operating Risks."

Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
gas may involve unprofitable efforts, not only from dry wells, but from wells
that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be

61
<PAGE>
curtailed, delayed or canceled as a result of numerous factors, many of which
are beyond the Company's control, including title problems, weather conditions,
mechanical problems, compliance with governmental requirements and shortages or
delays in the delivery of equipment and services. The Company's future drilling
activities may not be successful and, if unsuccessful, such failure may have a
material adverse effect on the Company's future results of operations and
financial condition.

In addition, the Company's use of 3-D seismic requires greater pre-drilling
expenditures than traditional drilling strategies. Although the Company believes
that its use of 3-D seismic will increase the probability of success of its
exploratory wells and should reduce average finding costs through the
elimination of prospects that might otherwise be drilled solely on the basis of
2-D seismic data and other traditional methods, unsuccessful wells are likely to
occur. There can be no assurance that the Company's participation in drilling
programs will be successful or that unsuccessful drilling efforts will not have
a material adverse effect on the Company.

ABANDONMENT COSTS

The Company is responsible for the payment of abandonment costs on its oil
and natural gas properties pro rata to its working interest. The Company accrues
for its expected future abandonment liabilities as a component of depletion,
depreciation and amortization as the properties are produced. As of December 31,
1996, total pro forma undiscounted abandonment costs estimated to be incurred
through the year 2006 were approximately $16.6 million for properties in federal
and state waters. The Company does not consider abandonment costs estimated to
be incurred on its onshore properties to be significant at this time. Estimates
of abandonment costs and their timing may change due to many factors, including
actual drilling and production results, inflation rates, and changes in
environmental laws and regulations.

The MMS requires lessees of OCS properties to post bonds in connection with
the plugging and abandonment of wells located offshore on the federal OCS and
the removal of all production facilities. Operators in the OCS waters of the
Gulf of Mexico are currently required to post an area-wide bond of $3.0 million
or $500,000 per producing lease, which the Company has provided. Under certain
circumstances, the MMS has the authority to suspend or terminate operations on
federal leases for failure to comply with the applicable bonding requirements or
other regulations applicable to plugging and abandonment. Any such suspensions
or terminations of the Company's operations could have a material adverse effect
on the Company's financial condition and results of operations.

TITLE TO PROPERTIES

The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and gas
industry. Prior to completing an acquisition of producing oil and natural gas
leases, the Company obtains title opinions on the most significant leases.
However, as is customary in the oil and gas industry, the Company makes only a
cursory review of title to farmout acreage and to undeveloped oil and natural
gas properties upon execution of the contracts pursuant to which the Company
acquires rights thereto. Prior to the commencement of drilling operations, a
thorough title examination is conducted and curative work is performed with
respect to significant defects. To the extent title opinions or other
investigations reflect title defects affecting farmout acreage or undeveloped
properties, the Company, rather than the seller of the undeveloped property, is
typically responsible for curing any such title defects at its expense. If the
Company were unable to remedy or cure any title defect of a nature such that it
would not be prudent to commence drilling operations on the property, the
Company could suffer a loss of its entire investment in the property. The
Company has obtained title opinions on substantially all of its producing
properties and believes that it has satisfactory title to such properties in
accordance with standards generally accepted in the oil and gas industry.

The Company's oil and natural gas properties are subject to customary
royalty interests, liens for current taxes and other burdens which the Company
believes do not materially interfere with the use of or affect the value of such
properties. Approximately 80% of the aggregate value of the Company's oil and
natural gas properties (other than the IPF Program properties) are and will
continue to be mortgaged to secure borrowings under the Revolving Credit
Facility. Although the remaining approximately 20% of the

62
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aggregate value of the Company's oil and natural gas properties are not
mortgaged to the Lenders under the Revolving Credit Facility, such properties
are nevertheless subject to the restrictions set forth therein, including a
prohibition on granting any security interests therein.

EMPLOYEES

On March 31, 1997, the Company employed 39 full-time persons and five
full-time contractors. The Company believes that its relationships with its
employees are good. None of the Company's employees are covered by a collective
bargaining agreement.

OFFICES

The Company currently leases approximately 31,000 square feet of office
space in Houston, Texas, where its principal offices are located.

LEGAL PROCEEDINGS

Various claims have been filed naming joint working interest owners of the
Company in the ordinary course of business, particularly claims alleging
personal injuries, for which the Company would be responsible for its pro rata
share of any uninsured damages or settlement costs. In addition, MarkWest
Michigan, Inc. ("MarkWest"), the Company's former partner in the Michigan
Development Project, has notified the Company that it believes that it had a
preferential purchase right with respect to a portion of the interest in the
project that the Company sold to a third party pursuant to the Michigan
Disposition. On April 29, 1997, MarkWest filed a demand for arbitration with the
American Arbitration Association seeking to enforce its alleged preferential
purchase right and claiming that the sale by the Company to the third party
should be declared void. The Company believes that MarkWest's claim has no
merit. On May 13, 1997, the Company filed an action in the District Court of
Harris County, Texas (234th Judicial District) against MarkWest seeking to stay
the arbitration proceedings initiated by MarkWest on the basis that the Company
was never a party to the agreement under which MarkWest alleges it has the right
to arbitrate its dispute with the Company.

No pending or threatened claims, actions or proceedings against the Company
are expected to have a material adverse effect on the Company's financial
condition or results of operations.

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MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The Company's Board of Directors currently has four members. Following the
Offering, the Company intends to increase the size of its Board of Directors to
six persons. The two individuals to be nominated for appointment to the Board of
Directors following the Offering are William P. Nicoletti and Gary K. Wright,
neither of whom are employees of or otherwise affiliated with the Company, Fund
VII or First Reserve. The new directors will be elected by the current
directors. All directors are elected annually to serve until the next annual
meeting of stockholders or until their successors are duly elected and
qualified. The officers of the Company are elected by, and serve until their
successors are elected by, the Board of Directors.

The following table sets forth certain information concerning the directors
and executive officers of the Company as of April 30, 1997.

NAME AGE POSITION
- ------------------------------------- --- -------------------------------------
Michael V. Ronca..................... 43 President and Chief Executive Officer
and Director
Herbert A. Newhouse.................. 52 Executive Vice President
Catherine L. Sliva................... 38 Executive Vice President and
Secretary
Rick G. Lester....................... 45 Vice President, Chief Financial
Officer and Treasurer
Jonathan S. Linker................... 48 Director and Chairman of the Board
William E. Macaulay.................. 51 Director
Steven H. Pruett..................... 35 Director
William P. Nicoletti*................ 51 Director
Gary K. Wright*...................... 52 Director
- ------------

* To be nominated for appointment to the Board of Directors following the
Offering.

Michael V. Ronca has been the President and Chief Executive Officer of the
Company and has served as a Director of the Company since its inception in 1996.
Mr. Ronca has been the President of Ventures Corporation since 1993. Prior to
starting Ventures Corporation, Mr. Ronca served as Executive Director, Investor
Relations for Tenneco where he was responsible for the development,
implementation and management of a global investor relations program. Mr. Ronca,
who was an employee of Tenneco for over 20 years, moved to Houston in 1984 to
assume the position of administrative assistant to the chairman and chief
executive officer of Tenneco Inc. In this capacity he focused on acquisition and
disposition analysis, strategic planning and operational issues. Mr. Ronca
graduated from Villanova University in 1975 with a bachelor of science degree in
Finance and Marketing and later earned a master of business administration
degree from Drexel University.

Herbert A. Newhouse has been Executive Vice President of the Company since
its inception in 1996. Mr. Newhouse is responsible for exploration, production
and evaluation activities for the Company, including geological, geophysical and
engineering technical evaluations. Mr. Newhouse joined Ventures Corporation in
1995 as Vice President. He has more than 28 years operational and managerial
experience in oil and gas exploration and production, most recently having
served as Vice President of Production for North Central Oil Corporation for the
six years prior to 1995. Before joining North Central, Mr. Newhouse spent 17
years with the exploration and production division of Tenneco Oil Company
("Tenneco Oil"), rising to the position of Division Production Manager
responsible for drilling, production, development geology and reservoir
engineering. He graduated from Ohio State University in 1968, with a bachelor of
science degree in Chemical Engineering.

Catherine L. Sliva has been the Executive Vice President and Secretary of
the Company since its inception in 1996 and is principally responsible for the
IPF Program, strategic planning and analysis, and investor relations. Ms. Sliva
has been with Tenneco Ventures since 1992. Ms. Sliva has 17 years experience in
offshore and onshore petroleum engineering and economics and is experienced in
production finance,

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acquisition evaluations, reservoir management, field development, economic
analysis, coordination of budgets and formulation of corporate goals and
strategies. A registered professional petroleum engineer, Ms. Sliva is a
graduate of Texas A&M University, where she received a bachelor of science
degree in Petroleum Engineering in 1980. Ms. Sliva joined Tenneco Oil in the
Gulf Coast division in 1980. She remained in the Gulf Coast division for five
years, advancing to Senior Petroleum Engineer. In 1985, Ms. Sliva became a
member of the Economic Planning and Analysis Group at Tenneco Oil. She evaluated
Tenneco Oil's exploration results, conducted an analysis of Tenneco Oil's
competitors and evaluated each division's profitability, including operating
results, manpower efficiencies, capital investment levels and results.

Rick G. Lester has been Vice President, Chief Financial Officer, Treasurer
and Assistant Secretary of the Company since its inception in 1996 with overall
responsibility for its accounting, financial analysis, financing and banking
activities. Mr. Lester joined Tenneco Ventures in 1992. Mr. Lester has 22 years
experience in the financial area, including accounting, tax, corporate finance,
and planning and analysis. He received his bachelor of business administration
degree in Accounting from the University of Oklahoma in 1974 and his Texas CPA
certificate in 1977, and is a member of the AICPA and the Texas Society of CPAs.
Mr. Lester joined Tenneco Oil in 1981 and was responsible at various times for
managing several operational accounting groups and the tax planning group. In
1988, Mr. Lester became Manager, Corporate Finance with Tenneco where he was
responsible for developing financing plans and negotiating credit agreements for
its U.S. and Canadian finance companies and for other special projects including
the review of its world-wide finance and stock repurchase programs.

Jonathan S. Linker has served as a Director of the Company since its
inception in 1996. Mr. Linker has been a Managing Director of First Reserve
since 1996, the President and a director of IDC Energy Corporation since 1987,
and a Vice President and director of Sunset Production Corporation since 1991.
First Reserve Corporation is an investment management firm specializing in
making private equity investments in energy companies. IDC Energy Corporation
and Sunset Production Corporation are small, privately-held oil and gas
companies. Mr. Linker also serves as a director of Hugoton Energy Corporation,
an independent oil and gas exploration and production company. Mr. Linker earned
a bachelor of arts degree in Geology from Amherst College, a master of arts
degree in Geology from Harvard University and a master of business
administration degree from the Harvard Business School.

William E. Macaulay has served as a Director of the Company since March
1997. Mr. Macaulay has been the President and Chief Executive Officer of First
Reserve since 1983. Mr. Macaulay serves as a director of Weatherford Enterra,
Inc., an oilfield service company, Maverick Tube Corporation, a manufacturer of
steel pipe and casing, TransMontaigne Oil Company, an oil products distribution
and refining company, National-Oilwell, Inc., a manufacturer and distributor of
equipment and products used in oil and gas drilling and production, and Hugoton
Energy Corporation. Mr. Macaulay earned a bachelor of arts degree in Economics
from City University of New York and a master of business administration degree
in Finance from the Wharton School at the University of Pennsylvania.

Steven H. Pruett has served as a Director of the Company since March 1997.
Mr. Pruett has been a Vice President of First Reserve since 1995. Mr. Pruett has
been the President and Chief Executive Officer of First Reserve Oil & Gas Co.
since 1996. First Reserve Oil & Gas Co. is a privately-held company engaged in
the acquisition and development of oil and gas properties in the Midcontinent
Region and the Permian Basin. Prior to joining First Reserve, Mr. Pruett worked
for Credit Suisse First Boston as an investment banker in the Natural Resources
Group in New York and Houston from 1994 to 1995. Mr. Pruett worked for Amoco
Production Company in Planning and Economics from 1991 to 1994, following his
graduation from the Harvard Business School with a master of business
administration degree in 1991. After earning a bachelor of science degree in
Petroleum Engineering from the University of Texas at Austin in 1984, Mr. Pruett
was a Petroleum Engineer for ARCO Oil and Gas Company from 1984 to 1989.

William P. Nicoletti will be nominated for appointment to the Board of
Directors following the Offering. Mr. Nicoletti has been Managing Director of
Nicoletti & Company Inc., a New York based private investment banking firm,
since 1991. Prior to founding Nicoletti & Company Inc., Mr. Nicoletti was

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a Managing Director and Head of the Energy and Natural Resources Group of
PaineWebber Incorporated. Mr. Nicoletti serves as Chairman of the Board of
Directors of Amerac Energy Corporation, an independent oil and gas company, and
is a director of Star Gas Corporation, a propane distribution company, and
StatesRail, Inc., a short line railroad holding company. Mr. Nicoletti earned a
bachelor of science degree in Mathematics from Seton Hall University and a
master of business administration degree in Finance from the Columbia University
Graduate School of Business.

Gary K. Wright will be nominated for appointment to the Board of Directors
following the Offering. Mr. Wright joined Texas Commerce Bank -- Houston in 1973
and is currently Manager of its Corporate Banking Department, with
responsibility for relationships with the bank's Energy and National Brands
Group. Mr. Wright is also Managing Director of the Global Oil and Gas Group for
The Chase Manhattan Bank and is the senior banker for the group in the
Southwest. Mr. Wright earned a bachelor of science degree in Petroleum
Engineering from Louisiana State University and a law degree from Loyola
University Law School.

COMMITTEES OF THE BOARD OF DIRECTORS

Following the Offering the Company will have an Audit Committee and a
Compensation Committee.

AUDIT COMMITTEE. The Board of Directors intends to name directors to an
Audit Committee after consummation of the Offering. The Audit Committee will
have responsibility for, among other things, (i) recommending the selection of
the Company's independent accountants, (ii) reviewing and approving the scope of
the independent accountants' audit activity and extent of non-audit services,
(iii) reviewing with management and the independent accountants the adequacy of
the Company's basic accounting systems, (iv) reviewing with management and the
independent accountants the Company's financial statements and exercising
general oversight of the Company's financial reporting process and (v) reviewing
the Company's litigation and other legal matters that may affect the Company's
financial condition and monitoring compliance with the Company's business ethics
and other policies.

COMPENSATION COMMITTEE. The Compensation Committee consists of Messrs.
Ronca, Linker and Pruett, and following the Offering, one of the independent
directors to be appointed to the Board of Directors will become a member of the
Compensation Committee. This committee has general supervisory power over, and
the power to grant options under, the Stock Purchase and Option Plan. The
Compensation Committee additionally has responsibility for, among other things,
(i) reviewing the recommendations of the Chief Executive Officer as to
appropriate compensation of the Company's principal executive officers and
certain other key personnel and establishing the compensation of such key
personnel and the Chief Executive Officer, (ii) examining periodically the
general compensation structure of the Company and (iii) supervising the employee
benefit plans and compensation plans of the Company.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During the Company's fiscal year ended December 31, 1996, the Company had
no compensation committee or other committee of the Board of Directors
performing similar functions. Decisions concerning compensation of Mr. Ronca
were made during such fiscal year by the Compensation Committee of the board of
directors of Tenneco, the former indirect parent of the Company's operating
subsidiaries. Decisions concerning compensation of the other executive officers
of the Company were made during fiscal year 1996 by the compensation committee
of Tennessee Gas Pipeline Company, the former parent of the Company's operating
subsidiaries. Mr. Ronca served as a member of the compensation committee of
Tennessee Gas Pipeline Company during fiscal year 1996.

RONCA EMPLOYMENT AGREEMENT

In connection with the Acquisition, the Company entered into a three-year
employment agreement with Mr. Ronca on December 31, 1996 pursuant to which Mr.
Ronca serves as the Company's President and Chief Executive Officer. Under the
Ronca Employment Agreement, Mr. Ronca receives an annual base salary of $180,000
and is entitled to receive an annual cash bonus based on the satisfaction of
performance criteria determined by the Board of Directors, in target and maximum
amounts equal to 50% and 90%,

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respectively, of such base salary. The Ronca Employment Agreement also provides
that Mr. Ronca will receive $20,000 annually to be used, at his discretion, for
perquisites and other fringe benefits associated with his position as President
and Chief Executive Officer of the Company. Mr. Ronca is additionally entitled
to participate in all other employee compensation and welfare benefit plans and
programs available to the Company's other senior executive officers, including
health, dental, group life, disability and retirement plans, and expense
reimbursement. In the event Mr. Ronca's employment is terminated prior to
December 31, 1999 and under certain circumstances, including an election by Mr.
Ronca to terminate his employment following a Change of Control (as therein
defined) or for Good Reason (as therein defined), he would be entitled under
such employment agreement to receive up to the full amount of the base salary he
would have received thereunder for the remaining term thereof had his employment
not been so terminated. Under the Ronca Employment Agreement, a "Change of
Control" is defined as the acquisition by any person or entity, or group
thereof, excluding Fund VII and other affiliates of First Reserve of more than
50% of the outstanding voting stock of the Company, and "Good Reason" is defined
to include, among other things, material reductions in Mr. Ronca's duties,
responsibilities or base salary.

COMPENSATION OF DIRECTORS

Prior to the Offering, directors of the Company have not received
compensation for their services in such capacity. The Company anticipates that,
after consummation of the Offering, directors who are employees of the Company
or its subsidiaries will not be paid any fees or additional compensation for
service as members of the Board of Directors or any committee thereof and that
the Company will enter into customary arrangements respecting fees and other
compensation (including expense reimbursement) for other directors of the
Company. Members of the Board of Directors who are not employees of the Company
or its subsidiaries will be eligible to receive options to purchase Common Stock
as described below under " -- Stock Option Plan for Nonemployee Directors."

STOCK OPTION PLAN FOR NONEMPLOYEE DIRECTORS

Effective upon consummation of the Offering, the Company plans to adopt the
Domain Energy Corporation 1997 Stock Option Plan for Nonemployee Directors (the
"Nonemployee Director Plan"). The objective of the Nonemployee Director Plan is
to enable the Company to attract and retain the services of outstanding
nonemployee directors by affording them an opportunity to acquire a proprietary
interest in the Company through automatic, non-discretionary awards of options
exercisable to purchase shares of Common Stock.

Each member of the Board of Directors who is not an employee of the Company
or its subsidiaries is eligible to receive options under the Nonemployee
Director Plan. On the effective date of the Nonemployee Director Plan, each such
eligible director will automatically be granted an option to purchase such
number of shares of Common Stock as will be determined by the Board of Directors
prior to consummation of the Offering. Future eligible directors will also be
granted an option to purchase an identical number of shares of Common Stock upon
their initial appointment or election to the Board of Directors. The exercise
price of the options will be equal to the fair market value of the Common Stock
on the date of grant. The options may be exercised for a period of ten years
commencing on the date of grant as follows: (i) up to one-third of the total
number of shares of Common Stock subject to an option may be purchased as of the
date of grant; (ii) up to an additional one-third of the total number of shares
of Common Stock subject to an option may be purchased as of the date of the
annual meeting of stockholders of the Company in the year following the year in
which the option was granted ("Second Vesting Date"), provided that the holder
of the option is an eligible director immediately following such meeting; and
(iii) the balance of the total number of shares of Common Stock subject to an
option may be purchased as of the date of the annual meeting of stockholders
next following the Second Vesting Date ("Final Vesting Date"), provided that the
holder of the option is an eligible director immediately following such meeting.
On the date of the annual meeting of stockholders of the Company that takes
place during the calendar year in which the first anniversary of the Final
Vesting Date of an option occurs, the holder of such option shall automatically
be granted an option to purchase such number of shares of Common Stock as will
be determined by the Board of Directors prior to

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consummation of the Offering, provided that the holder of the option is an
eligible director immediately following such meeting.

EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table sets forth certain information with respect to the
compensation of the Company's chief executive officer and for each of its other
executive officers (the "named executive officers") during fiscal year 1996.

ANNUAL
COMPENSATION(1)
NAME AND --------------------- ALL OTHER
PRINCIPAL POSITION SALARY BONUS COMPENSATION(2)
- ------------------------------------- -------- -------- ----------------
Michael V. Ronca..................... $185,120 $160,000 $9,500
President and Chief Executive
Officer
Herbert A. Newhouse.................. 150,800 70,000 9,500
Executive Vice President
Catherine L. Sliva................... 98,040 38,400 7,843
Executive Vice President and
Secretary
Rick G. Lester....................... 114,060 39,200 9,125
Vice President, Chief Financial
Officer and Treasurer

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

(1) Does not include the value of perquisites and other personal benefits,
securities or property because the aggregate amount of such compensation, if
any, does not exceed the lesser of $50,000 or 10 percent of the total amount
of annual salary and bonus for the named executive officers.

(2) Represents contributions of Tenneco under its 401(k) plan. Does not include
options to acquire shares of common stock of Tenneco granted to Mr. Ronca,
Mr. Newhouse, Ms. Sliva and Mr. Lester or restricted stock awards made to
Mr. Ronca and Mr. Newhouse, all of which were granted or awarded in January
1996 as compensation for performance in 1995.

STOCK PURCHASE AND OPTION PLAN

The Company recently adopted the Amended and Restated 1996 Stock Purchase
and Option Plan for Key Employees of Domain Energy Corporation and Affiliates
(the "Stock Purchase and Option Plan"). The objectives of the Stock Purchase and
Option Plan are (i) to attract and retain management personnel with the
training, experience and ability to enable them to make a substantial
contribution to the success of the Company's business, (ii) to motivate
management personnel by means of growth-related incentives to achieve long range
goals and (iii) to further the alignment of interests of participants with those
of the Company's stockholders through opportunities for increased stock or
stock-based ownership in the Company.

The Stock Purchase and Option Plan authorizes the issuance of options to
acquire up to 867,091 shares of Common Stock, and the Company has reserved
867,091 shares of Common Stock for issuance in connection therewith. The Stock
Purchase and Option Plan will be administered by the Compensation Committee of
the Board of Directors. Pursuant to the Stock Purchase and Option Plan, the
Company may grant to employees, directors or other persons having a unique
relationship with the Company or its affiliates, singly or in combination,
Incentive Stock Options, Other Stock Options, Stock Appreciation Rights,
Restricted Stock, Purchase Stock, Dividend Equivalent Rights, Performance Units,
Performance Shares or Other Stock-Based Grants, in each case as such terms are
defined therein. See " -- Stock Option Agreements." The terms of any such grant
will be determined by the Compensation Committee and set forth in a separate
grant agreement. The exercise price will be at least equal to 100% of fair
market value of the Common Stock on the date of grant in the case of Incentive
Stock Options and the exercise price of Other Stock Options will be at least
equal to 50% of fair market value of the Common Stock on the date of grant,
provided that options to purchase up to 433,546 shares of Common Stock may be
granted with an exercise price equal to $.01 per share, which is the par value
of the Common Stock. Non-Qualified Stock Options and Other Stock Options may be
exercisable for up to ten years. The Compensation Committee

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may provide that an optionee may pay for shares upon exercise of an option: (i)
in cash; (ii) in already-owned shares of Common Stock; (iii) by payment through
a cash or margin arrangement with a broker; (iv) in shares otherwise issuable
upon exercise of the option; or (v) by any combination of (i) through (iv) as
authorized by the Compensation Committee. In the event of certain extraordinary
transactions, including a merger, consolidation, a sale or transfer of all or
substantially all assets or an acquisition of all or substantially all the
Common Stock, vesting of such options will generally be accelerated. The Stock
Purchase and Option Plan will terminate on December 31, 2006.

STOCK OPTION AGREEMENTS

On February 21, 1997 (the "Grant Date"), the Company granted to the
following persons the following options under the Stock Purchase and Option
Plan, pursuant to separate Non-Qualified Stock Option Agreements between the
Company and each of such persons (collectively, as amended, the "Stock Option
Agreements"): (i) an option to purchase up to 339,300 shares of Common Stock to
Michael V. Ronca, the President and Chief Executive Officer of the Company, (ii)
an option to purchase up to 113,100 shares of Common Stock to Herbert A.
Newhouse, an Executive Vice President of the Company, (iii) an option to
purchase up to 113,100 shares of Common Stock to Catherine L. Sliva, an
Executive Vice President and the Secretary of the Company, (iv) an option to
purchase up to 50,266 shares of Common Stock to Rick G. Lester, a Vice
President, the Chief Financial Officer and the Treasurer of the Company, (v) an
option to purchase up to 50,266 shares of Common Stock to Douglas H. Woodul, the
Vice President -- Production of the Company, (vi) an option to purchase up to
50,266 shares of Common Stock to Steven M. Curran, the Vice President --
Exploration of the Company, (vii) an option to purchase up to 18,850 shares of
Common Stock to Dean R. Bouillion, the Vice President -- Land of the Company,
and (viii) an option to purchase up to 18,850 shares of Common Stock to Lucynda
S. Herrin, an Assistant Controller of the Company. In addition, the Company has
granted options to purchase an aggregate of 95,696 shares of Common Stock to
other employees of the Company. Under the terms of the Stock Option Agreements,
50% of the options granted to each such person are designated as time options
(collectively, the "Time Options"), with an exercise price equal to $4.18 per
share, and 50% are designated as performance options (collectively, the
"Performance Options"), with an exercise price equal to $.01 per share. The Time
Options become exercisable as to 20% of the shares of Common Stock subject
thereto on the first anniversary of the Grant Date and are thereafter
exercisable as to an additional 20% of such shares upon each anniversary
thereafter. The Performance Options become exercisable at any time following the
second anniversary of the Grant Date, when the Investment Return Hurdle (as such
term is defined below) is met; provided that the Performance Options become
exercisable as to 100% of the shares of Common Stock subject thereto on the
ninth anniversary of the Grant Date.

The following terms have the following meanings under the Stock Option
Agreements:

"EQUITY VALUE" means the sum of:

(i) all amounts actually received by the FRC Entities from time to time
on a cumulative basis through the date of determination of (A) cash
(x) through any cash dividend or other distribution on account of the
Investor Stock or (y) in connection with either (1) any disposition
(whether by way of redemption, repurchase, repayment, merger or
otherwise) of all or any part of the Investor Stock or of securities
or other non-cash property previously received by way of a dividend
or other distribution on account of the Investor Stock, but only to
the extent Investor Stock or other securities or non-cash property is
so disposed and excluding any disposition to one or more other FRC
Entities, (2) a disposition of any or all of the assets of the
Company or any of its subsidiaries, or (3) a recapitalization of the
Company or its subsidiaries, or (B) securities or any other non-cash
property (valued at their fair market value) in connection with
either (x) any disposition (whether by sale, merger or otherwise) of
all or any part of the Investor Stock to a third party, but only to
the extent Investor Stock is so disposed and excluding any
disposition to one or more other FRC Entities, or (y) any disposition
of any or all of the assets of the Company or any of its subsidiaries
(it being understood that for purposes of this clause (i), the terms
"disposition," "dispose," and "disposed" shall not include the
creation of a pledge, lien or

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other similar encumbrance unless and until foreclosed upon);
PROVIDED, that when determining the amount actually received by the
FRC Entities after delivery of a notice that the options will be
terminated upon the merger of the Company, the exchange of all or
substantially all of its assets for the securities of another
Company, a Change of Control, or the recapitalization,
reclassification, liquidation or dissolution of the Company, the
amount actually received will be deemed to include any amounts to be
received by the FRC Entities pursuant to the transaction giving rise
to the termination of the options (to the extent such amounts would
otherwise qualify as amounts received pursuant to clauses (A) and (B)
above); plus, if applicable,

(ii) to the extent the Equity Value is being determined prior to the fifth
anniversary of the Grant Date, an amount with respect to each unsold
share of Common Stock then owned by the FRC Entities equal to the
Trading Value (as therein defined) thereof as of such date.

"FRC ENTITIES" means investment funds or other entities for which First
Reserve acts as a general and/or managing partner or in respect of which First
Reserve provides investment advice, either directly or through entities
controlled by it.

"INVESTMENT" means $30.0 million invested by the FRC Entities in Investor
Stock on the closing date of the Acquisition, plus the amount of any additional
cash invested by the FRC Entities in Investor Stock after such closing date.
Expressly excluded from such term is the $8.0 million loan made by Fund VII to
Domain Energy Guarantor Corporation and evidenced by the Subordinated Promissory
Note dated December 31, 1996. See "Transactions With Management and First
Reserve -- Indebtedness to Fund VII."

"INVESTMENT RETURN HURDLE" will be satisfied when the Equity Value with
respect to the Investor Stock is equal to or greater than, as of the date of
determination, the amount determined by increasing the Investment at a
compounded annual rate of 25% commencing on the date of any cash investment by
the FRC Entities (as to that portion of the Investment made on such date)
through and including such date of determination.

"INVESTOR STOCK" means issued and outstanding shares of capital stock of
any class or series of the Company, so long as such shares were originally
acquired by the FRC Entities from the Company.

401(K) PLAN

The Company has offered its employees an employee 401(k) savings plan (the
"401(k) Plan"), which became effective upon inception of the Company. The 401(k)
Plan covers all employees and entitles each to contribute up to 15% of his or
her annual compensation subject to maximum limitations imposed by the Internal
Revenue Code. The 401(k) Plan allows for employer matching of up to 8% of the
employee's contributions based on years of participation in the plan, including
years of participation in the 401(k) plan previously offered by Tenneco.

LIMITATION OF DIRECTORS' LIABILITY; INDEMNIFICATION OF DIRECTORS AND OFFICERS

The Company's Certificate of Incorporation provides that no director of the
Company shall be liable to the Company or its stockholders for monetary damages
for breach of fiduciary duty or the duty of care as a director, except for
liability for breach of the director's duty of loyalty, acts not in good faith,
intentional misconduct or knowing violations of law, unlawful payment of
dividends or stock purchases or redemptions, or transactions in which the
director derived an improper personal benefit. The Certificate of Incorporation
also provides for the indemnification of officers and directors to the fullest
extent permitted by Delaware law. The Company also maintains directors' and
officers' liability insurance coverage.

Generally, Section 145 of the Delaware General Corporation Law, as amended
(the "DGCL"), provides that a corporation may indemnify any person who is or was
a party or is threatened to be made a party to any threatened, pending or
completed action, including any action by or in the right of the corporation
(unless such person was adjudged liable to the corporation, in which event
indemnification is permitted if, but only to the extent that, the court in which
such action was brought determined such indemnification is fair and reasonable)
by reason of the fact that such person is or was a director, officer, employee
or agent of the corporation, or is or was serving in such capacity for another
corporation or entity

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at the request of the corporation, if he acted in good faith and in a manner he
reasonably believed to be in or not opposed to the best interests of the
corporation and, with respect to any criminal action or proceeding, had no
reasonable cause to believe his conduct was unlawful. Such indemnification may
include all expenses (including attorneys' fees) and, in the case of any action
other than an action by or in the right of the corporation, all judgments, fines
and amounts paid in settlement, to the extent such expenses, judgments, fines
and amounts were actually paid and reasonably incurred by the indemnified party
in connection with such action.

TRANSACTIONS WITH MANAGEMENT AND FIRST RESERVE

SECURITYHOLDERS AGREEMENT

The Company, Fund VII and the Company's officers who have purchased Common
Stock (the "Management Investors") are parties to Securityholders Agreement
dated as of December 31, 1996 (the "Securityholders Agreement"). The
Securityholders Agreement contains provisions governing the management of the
Company, voting of shares, election of directors and restrictions on transfer of
shares, all of which terminate automatically upon the completion of the
Offering. In addition, the Securityholders Agreement provides Fund VII, after
the Offering, the right on four occasions to require the Company to register all
or part of Fund VII's registrable shares of Common Stock under the Securities
Act, and the Company is required to use its reasonable best efforts to effect
such registration, subject to certain conditions and limitations. Upon the
Company's receipt of a demand from Fund VII to register all or part of its
registrable shares, the Company is required to notify the other parties to the
Securityholders Agreement of the demand, and such parties shall, subject to
certain conditions and limitations, have the right to include the registrable
shares held by them in such registration. The Securityholders Agreement also
provides all the parties thereto with piggyback registration rights on any
offering by the Company of any of its securities to the public except a
registration on Forms S-4 or S-8 under the Securities Act; provided, however,
that until two years after the date of the Offering, the Management Investors
will not have piggyback registration rights with respect to any registration in
which Fund VII or any of its permitted transferees are not participating. The
Company will bear the expenses of all registrations under the Securityholders
Agreement. Fund VII has waived its registration rights with respect to a
Registration Statement filed by the Company with respect to the Offering.

MANAGEMENT INVESTOR SUBSCRIPTION AGREEMENTS AND RELATED TRANSACTIONS

Shortly before the Offering, each of the Management Investors entered into
a Management Investor Subscription Agreement with the Company pursuant to which
the Management Investors purchased an aggregate of 390,307 shares of Common
Stock. To facilitate such purchases, the Company loaned the Management Investors
the following amounts: (i) Mr. Ronca ($249,200), (ii) Mr. Newhouse ($87,000),
(iii) Ms. Sliva ($35,445), (iv) Mr. Lester ($50,011), (v) Mr. Woodul ($49,763),
(vi) Mr. Curran ($50,376) and (vii) Ms. Herrin ($24,231). All such indebtedness
of such persons accrues interest at the rate of 8% per annum, payable
semiannually; provided that each Management Investor may elect to satisfy his or
her semiannual interest payment obligation by increasing the principal amount of
the indebtedness owed to the Company by the amount of interest otherwise
payable. As security for such loans made by the Company, each Management
Investor pledged to the Company, and granted a first priority security interest
in, the shares of Common Stock purchased by such Management Investor pursuant to
its respective Management Investor Subscription Agreement and is required to
pledge, and grant a first priority security interest in, all other shares of
Common Stock that each such person may subsequently acquire, including, without
limitation, upon exercise of options to purchase shares of Common Stock. As of
April 30, 1997, the outstanding indebtedness of each Management Investor to the
Company was equal to the original principal amount loaned to such Management
Investor as indicated above plus interest accrued thereon.

FIRST RESERVE TRANSACTION FEE

For financial advisory services rendered in connection with the
Acquisition, the Company agreed to pay First Reserve a fee of $500,000.

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INDEBTEDNESS TO FUND VII

Prior to the Acquisition, Tennessee Gas Pipeline Company ("TGPL"), the
former wholly-owning parent of Ventures Corporation, was a guarantor with
respect to certain indebtedness (the "Michigan Senior Debt") of a partnership
formed to participate in the Michigan Development Project in which Ventures
Corporation was at the time a general partner. In connection with the
Acquisition, the Company formed Domain Energy Guarantor Corporation, a Delaware
corporation ("Guarantor Corporation"), for the sole purpose of assuming the
obligations of TGPL under such guaranty. As security for its obligations under
the guaranty, Guarantor Corporation purchased an $8.0 million certificate of
deposit issued by the lender in respect of the Michigan Senior Debt and assigned
and pledged such certificate to the lender.

To enable Guarantor Corporation to purchase the $8.0 million certificate
pledged as collateral for its guaranty of the Michigan Senior Debt, Fund VII
loaned Guarantor Corporation $8.0 million evidenced by a Subordinated Promissory
Note dated December 31, 1996 (the "Note"). The full principal amount of the Note
matures on December 31, 1999. Interest accrues on the Note at a rate per annum
equal to the interest rate per annum earned by Guarantor Corporation on the $8.0
million certificate and is payable quarterly. The obligations of Guarantor
Corporation under the Note are expressly made subordinate and subject in right
of payment to the prior payment in full of the Michigan Senior Debt. Upon
consummation of the Michigan Disposition, the Michigan Senior Debt was repaid in
full and the pledge of the $8.0 million certificate was released.

ACQUISITION OF COMMON STOCK BY FUND VII

Pursuant to the Subscription Agreement dated December 31, 1996 (the "First
Reserve Subscription Agreement"), between the Company and Fund VII, the Company
granted to Fund VII an option (the "First Reserve Option") to acquire 1,914,048
shares of Common Stock for an aggregate purchase price of $8.0 million plus any
cash interest payment on the Note actually received by Fund VII (the "Option
Price"). The Option Price could be paid by Fund VII (i) prior to the date on
which the Note has been paid in full, by delivery to the Company of the Note
together with the payment in cash of any principal or interest payments on the
Note previously received by Fund VII and (ii) after the date on which the Note
has been paid in full, by payment of the Option Price in cash. In connection
with the Offering, the Company and Fund VII have agreed to restructure the terms
of the First Reserve Option as set forth below.

The Company and Fund VII have agreed that concurrently with consummation of
the Offering, Fund VII will purchase 643,037 shares of Common Stock, at a price
per share equal to the Price to Public set forth on the cover page of this
Prospectus, for an aggregate purchase price of $8,681,000. The amount of
$8,681,000 represents the sum of (i) the outstanding principal balance of the
Note plus estimated accrued interest thereon through June 15, 1997 and (ii)
$500,000 to be paid in cash by Fund VII. See "-- Indebtedness to Fund VII."

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT

The following table sets forth certain information as of the date of this
Prospectus concerning the persons known by the Company to be beneficial owners
of more than five percent of the Company's outstanding Common Stock, the members
of the Board of Directors of the Company, the named executive officers listed in
the Summary Compensation Table above and all directors and executive officers of
the Company as a group.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
-------------------------------------------------
PRIOR TO OFFERING SUBSEQUENT TO OFFERING
----------------------- -----------------------
NAME OF BENEFICIAL OWNER SHARES PERCENT SHARES PERCENT
- ---------------------------------------- ----------- ------- ----------- -------
<S> <C> <C> <C> <C> <C>
First Reserve Corporation(1)............ 7,177,681 93.7% 7,820,718(4) 54.7%
475 Steamboat Road
Greenwich, Connecticut 06830
William E. Macaulay(2).................. 7,177,681(3) 93.7 7,820,718(4) 54.7
475 Steamboat Road
Greenwich, Connecticut 06830
John A. Hill(2)......................... 7,177,681(3) 93.7 7,820,718(4) 54.7
475 Steamboat Road
Greenwich, Connecticut 06830
Michael V. Ronca........................ 179,442 2.3 179,442 1.3
Herbert A. Newhouse..................... 59,813 * 59,813 *
Catherine L. Sliva...................... 39,955 * 39,955 *
Rick G. Lester.......................... 29,913 * 29,913 *
Jonathan S. Linker...................... -- -- -- --
Steven H. Pruett........................ -- -- -- --
William P. Nicoletti.................... -- -- -- --
Gary K. Wright.......................... -- -- -- --
All directors and executive officers as
a group (9 persons)................... 7,486,804(3) 97.7 8,129,841(4) 56.8
</TABLE>
- ------------
* Less than 1%.

(1) Shares of Common Stock shown as owned by First Reserve Corporation are owned
of record by Fund VII, of which First Reserve Corporation is the sole
general partner and as to which it possesses sole voting and investment
power.

(2) Messrs. Macaulay and Hill may be deemed to share beneficial ownership of the
shares shown as beneficially owned by First Reserve Corporation as a result
of Messrs. Macaulay and Hill's ownership of common stock of First Reserve
Corporation. Messrs. Macaulay and Hill disclaim beneficial ownership of such
shares.

(3) Includes 7,177,681 shares beneficially owned by First Reserve Corporation.

(4) Includes 7,177,681 shares beneficially owned by First Reserve Corporation
and 643,037 shares to be purchased by Fund VII concurrently with
consummation of the Offering.

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<PAGE>
DESCRIPTION OF CAPITAL STOCK

THE FOLLOWING SUMMARY DESCRIPTION OF THE COMPANY'S CAPITAL STOCK IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO THE COMPANY'S CERTIFICATE OF
INCORPORATION, A COPY OF WHICH HAS BEEN INCLUDED AS AN EXHIBIT TO THE
REGISTRATION STATEMENT OF WHICH THIS PROSPECTUS IS A PART. ALL CAPITALIZED TERMS
USED AND NOT DEFINED BELOW HAVE THE RESPECTIVE MEANINGS ASSIGNED TO THEM IN THE
CERTIFICATE OF INCORPORATION.

COMMON STOCK

The Company is authorized to issue up to 25,000,000 shares of Common Stock,
$.01 par value per share. As of the date of this Prospectus, there were
7,663,684 shares of Common Stock issued and outstanding. Immediately after
completion of the Offering, 14,306,721 shares of Common Stock will be issued and
outstanding.

Holders of Common Stock are entitled to one vote for each share held, are
not entitled to cumulative voting for the purpose of electing directors and have
no preemptive or similar right to subscribe for, or to purchase, any shares of
Common Stock or other securities to be issued by the Company in the future.
Accordingly, the holders of more than 50% in voting power of the shares of
Common Stock voting generally for the election of directors will be able to
elect all of the Company's directors. Immediately after completion of the
Offering and the concurrent sale to Fund VII, Fund VII will own 54.7% of the
outstanding shares of Common Stock of the Company (or 51.4% if the
over-allotment option is exercised in full) and will be in a position to control
actions that require the consent of stockholders, including the election of
directors, payment of dividends, amendment of the Certificate of Incorporation
and mergers or a sale of substantially all of the assets of the Company.

Holders of shares of Common Stock have no exchange, conversion or
preemptive rights and such shares are not subject to redemption. All outstanding
shares of Common Stock are, and upon issuance the shares of Common Stock offered
hereby will be, duly authorized, validly issued, fully paid and nonassessable.
Subject to the prior rights, if any, of holders of any outstanding class or
series of capital stock having a preference in relation to the Common Stock as
to distributions upon the dissolution, liquidation and winding-up of the Company
and as to dividends, holders of Common Stock are entitled to share ratably in
all assets of the Company which remain after payment in full of all debts and
liabilities of the Company, and to receive ratably such dividends, if any, as
may be declared by the Company's Board of Directors from time to time out of
funds and other assets legally available therefor. See "Dividend Policy" and
"Capitalization."

PREFERRED STOCK

The Board of Directors is authorized, without action by the holders of
Common Stock, to issue up to 5,000,000 shares of preferred stock, $.01 par value
(the "Preferred Stock"), in one or more series, to establish the number of
shares to be included in each such series and to fix the designations,
preferences, relative, participating, optional and other special rights of the
shares of each such series and the qualifications, limitations and restrictions
thereof. Such matters may include, among others, voting rights, conversion and
exchange privileges, dividend rates, redemption rights, sinking fund provisions
and liquidation rights that could be superior and prior to the Common Stock.

The issuance of one or more series of the Preferred Stock could, under
certain circumstances, adversely affect the voting power of the holders of the
Common Stock and could have the effect of discouraging or making more difficult
any attempt by a person or group to effect a change in control of the Company.

DELAWARE BUSINESS COMBINATION STATUTE

The Company is a Delaware corporation and is subject to Section 203 of the
DGCL ("Section 203"). In general, Section 203 prevents an "interested
stockholder" (defined generally as a person owning 15% or more of a
corporation's outstanding voting stock) from engaging in a "business
combination" (as therein defined) with a Delaware corporation for three years
following the time that such person became an interested stockholder, unless (i)
before such person became an interested stockholder, the board of

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directors of the corporation approved the business combination in question or
the transaction which resulted in such person becoming an interested
stockholder, (ii) upon consummation of the transaction that resulted in the
interested stockholder's becoming such, the interested stockholder owns at least
85% of the voting stock of the corporation outstanding at the time such
transaction commenced (excluding stock held by directors who are also officers
of the corporation and by employee stock plans that do not provide employees
with rights to determine confidentially whether shares held subject to the plan
will be tendered in a tender or exchange offer), or (iii) at or following the
transaction in which such person became an interested stockholder, the business
combination is approved by the board of directors of the corporation and
authorized at a meeting of stockholders by the affirmative vote of the holders
of not less than 66 2/3% of the outstanding voting stock of the corporation not
owned by the interested stockholder. Under Section 203, the restrictions
described above do not apply to certain business combinations proposed by an
interested stockholder following the announcement (or notification) of one of
certain extraordinary transactions involving the corporation and a person who
had not been an interested stockholder during the preceding three years or who
became an interested stockholder with the approval of the corporation's
directors or at a time when the restrictions imposed by Section 203 did not
apply in accordance with the terms thereof, and which transactions are approved
or not opposed by a majority of the members of the board of directors then in
office who were directors prior to any person becoming an interested stockholder
during the previous three years or were recommended for election or elected to
succeed such directors by a majority of such directors. Fund VII is not subject
to the restrictions contained in Section 203 because the transaction that
resulted in Fund VII becoming an interested stockholder (i.e., the sale of
shares of Common Stock to Fund VII to finance the Acquisition pursuant to the
First Reserve Subscription Agreement) was approved by the Board of Directors.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Stock is ChaseMellon
Shareholder Services, L.L.C.

SHARES ELIGIBLE FOR FUTURE SALE

Upon completion of the Offering and the Concurrent Sale, the Company will
have outstanding an aggregate of 14,306,721 shares of Common Stock. All of the
6,000,000 shares sold in the Offering (6,900,000 shares if the over-allotment
option granted to the Underwriters is exercised in full) will be freely
tradeable without restriction or further registration under the Securities Act,
except for any shares purchased by "affiliates" of the Company, as that term is
defined in Rule 144 under the Securities Act (whose sales would be subject to
certain limitations and restrictions described below).

The 7,663,684 shares of Common Stock held by the Company's existing
stockholders were, and the 643,037 shares of Common Stock to be purchased by
Fund VII concurrently with consummation of the Offering will be, issued and sold
by the Company in reliance on an exemption from the registration requirements of
the Securities Act. Substantially all of the outstanding shares of Common Stock
held by the Company's existing stockholders after the Offering will be subject
to the "lock-up" agreement described below. After expiration of such lock-up
agreement 180 days after the date of this Prospectus, the Common Stock then
owned by such stockholders may be resold only upon registration under the
Securities Act or pursuant to an exemption from such registration requirements,
including exemptions contained in Rule 144. The Securityholders Agreement
provides Fund VII, after the Offering, the right on four occasions to require
the Company to register all or part of Fund VII's registrable shares of Common
Stock (which includes the Common Stock to be purchased in the Concurrent Sale)
under the Securities Act, and the Company is required to use its reasonable best
efforts to effect such registration, subject to certain conditions and
limitations. Upon the Company's receipt of a demand from Fund VII to register
all or part of its registrable shares, the Company is required to notify the
other parties to the Securityholders Agreement of the demand and such parties
shall, subject to certain conditions and limitations, have the right to include
the registrable shares held by them in such registration. The Securityholders
Agreement also provides all the parties thereto with piggyback registration
rights on any offering by the Company of any of its securities to the public
except a registration on Forms S-4 or S-8 under the Securities Act; provided,
however, that until two years

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<PAGE>
after the date of the Offering, the Management Investors will not have piggyback
registration rights with respect to any registration in which Fund VII or any of
its permitted transferees are not participating. Fund VII has waived its
registration rights with respect to a Registration Statement filed by the
Company with respect to the Offering and has informed the Company that it has no
immediate plans to sell or otherwise dispose of shares of the Common Stock.

In general, under Rule 144 as currently in effect, a person (or persons
whose shares are aggregated) who has beneficially owned shares of a public
company for at least one year (including the holding period of any prior owner
except an affiliate) that were not acquired in a public offering is entitled to
sell in "broker's transactions" or to market makers, within any three-month
period, a number of shares that does not exceed the greater of (i) 1% of the
number of shares of Common Stock then outstanding (approximately 143,067 shares
immediately after the Offering) or (ii) generally, the average weekly trading
volume in the Common Stock during the four calendar weeks preceding the required
filing of a Form 144 with respect to such sale. Sales under Rule 144 are
generally subject to the availability of current public information about the
Company. Under Rule 144(k), a person who is not deemed to have been an affiliate
of the Company at any time during the 90 days preceding a sale, and who has
beneficially owned the shares proposed to be sold for at least two years, is
entitled to sell such shares without having to comply with the manner of sale,
public information, volume limitation or notice filing provisions of Rule 144.

As soon as practicable following the Offering, the Company intends to file
a registration statement on Form S-8 under the Securities Act covering 867,091
shares of Common Stock reserved for issuance pursuant to its Stock Purchase and
Option Plan and such number of shares of Common Stock as will be reserved for
issuance pursuant to its Nonemployee Director Plan. Shares of Common Stock
issued upon exercise of the stock options granted under the Stock Purchase and
Option Plan after the effective date of such registration statement will be
freely tradeable, except for any such shares acquired by an "affiliate" of the
Company, as that term is defined in Rule 144 under the Securities Act.

The Company, each of the Company's directors and executive officers and
Fund VII have agreed not to sell, offer to sell, contract to sell, grant any
option for the sale of or otherwise dispose of, directly or indirectly, any
shares of Common Stock or any securities convertible into or exercisable or
exchangeable for any Common Stock owned by any of them prior to the expiration
of 180 days from the date of this Prospectus, except (i) for shares of Common
Stock offered hereby, (ii) with the prior written consent of Credit Suisse First
Boston Corporation, and (iii) for the issuance of shares pursuant to employee
benefit plans of the Company, provided that the Company has agreed not to grant
options to purchase shares of Common Stock at a price less than the Offering
price.

Prior to the Offering, there has been no public market for the Common
Stock, and no prediction can be made as to the effect, if any, that future sales
of shares or the availability of shares for sale will have on the market price
for Common Stock prevailing from time to time. Sales of substantial amounts of
Common Stock in the public market, or the perception of the availability of
shares for sale, could adversely affect the prevailing market price of the
Common Stock and could impair the Company's ability to raise capital through the
sale of its equity securities.

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<PAGE>
UNDERWRITING

Under the terms and subject to the conditions contained in an Underwriting
Agreement dated June 23, 1997 (the "Underwriting Agreement"), the underwriters
named below (the "Underwriters"), for whom Credit Suisse First Boston
Corporation, PaineWebber Incorporated, Prudential Securities Incorporated and
Morgan Keegan & Company, Inc. are acting as representatives (the
"Representatives"), have severally but not jointly agreed to purchase from the
Company the following respective numbers of Shares:

NUMBER
UNDERWRITER OF SHARES
- ---------------------------------------- ---------
Credit Suisse First Boston
Corporation ................................................ 1,152,000
PaineWebber Incorporated ..................................... 1,152,000
Prudential Securities Incorporated ........................... 1,152,000
Morgan Keegan & Company, Inc. ................................ 384,000
Arneson, Kercheville & Associates,
Inc ........................................................ 60,000
Bear, Stearns & Co. Inc. ..................................... 120,000
Donaldson, Lufkin & Jenrette Securities
Corporation ................................................ 120,000
Gaines, Berland Inc. ......................................... 60,000
Gerard Klauer Mattison & Co., Inc. ........................... 60,000
Goldman, Sachs & Co. ......................................... 120,000
Howard, Weil, Labouisse, Friedrichs
Incorporated ............................................... 120,000
Invemed Associates, Inc. ..................................... 120,000
Jefferies & Company, Inc. .................................... 120,000
Johnson Rice & Company L.L.C ................................. 60,000
Merrill Lynch, Pierce, Fenner & Smith
Incorporated ............................................... 120,000
Morgan Stanley & Co. Incorporated ............................ 120,000
Nesbitt Burns Securities Inc. ................................ 60,000
Oppenheimer & Co., Inc. ...................................... 120,000
Petrie Parkman & Co. ......................................... 120,000
Principal Financial Securities, Inc. ......................... 60,000
Rauscher Pierce Refsnes, Inc. ................................ 60,000
Raymond James & Associates, Inc. ............................. 60,000
Salomon Brothers Inc. ........................................ 120,000
Sanders Morris Mundy ......................................... 60,000
Southcoast Capital Corporation ............................... 60,000
Starr Securities, Inc. ....................................... 60,000
Stephens Inc. ................................................ 60,000
TD Securities (USA) Inc. ..................................... 120,000
---------
Total ................................................... 6,000,000
=========

The Underwriting Agreement provides that the obligations of the
Underwriters are subject to certain conditions precedent and that the
Underwriters will be obligated to purchase all of the shares offered hereby
(other than those shares covered by the over-allotment option described below)
if any are purchased. The Underwriting Agreement provides that, in the event of
a default by an Underwriter in certain circumstances, the purchase commitments
of non-defaulting Underwriters may be increased or the Underwriting Agreement
may be terminated.

The Company has granted to the Underwriters an option expiring at the close
of business on the 30th day after the date of this Prospectus, to purchase up to
900,000 additional shares of Common Stock (the "Option Shares") at the initial
public offering price, less the underwriting discounts and commissions, all as
set forth on the cover page of this Prospectus. Such option may be exercised
only to cover over-allotments, if any, in the sale of the shares offered hereby.
To the extent that this option to purchase is

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<PAGE>
exercised, each Underwriter will become obligated, subject to certain
conditions, to purchase approximately the same percentage of Option Shares as
the number of shares set forth next to such Underwriter's name in the preceding
table bears to the sum of the total number of shares in such table it was
obligated to purchase pursuant to the Underwriting Agreement.

The Company has been advised by the Representatives that the Underwriters
propose to offer the shares offered hereby to the public initially at the public
offering price set forth on the cover page of this Prospectus and, through the
Representatives, to certain dealers at such price less a concession of $0.555
per share, and the Underwriters and such dealers may allow a discount of $0.10
per share on sales to other dealers. After the initial public offering, the
public offering price and concession and discount to dealers may be changed by
the Representatives.

The Company has agreed to indemnify the Underwriters against certain
liabilities, including civil liabilities under the Securities Act, or contribute
to payments which the Underwriters may be required to make in respect thereto.

The Company, each of the Company's directors and executive officers and
Fund VII have agreed not to sell, offer to sell, contract to sell, grant any
option for the sale of or otherwise dispose of, directly or indirectly, any
shares of Common Stock or any securities convertible into or exercisable or
exchangeable for any Common Stock owned by any of them prior to the expiration
of 180 days from the date of this Prospectus, except (i) for shares of Common
Stock offered hereby, (ii) with the prior written consent of Credit Suisse First
Boston Corporation and (iii) for the issuance of shares pursuant to employee
benefit plans of the Company, provided that the Company has agreed not to grant
options to purchase shares of Common Stock at a price less than the Offering
price.

In connection with the Acquisition, the Company paid PaineWebber
Incorporated a fee of $2.1 million for financial advisory services.

The Representatives have informed the Company that they do not expect
discretionary sales by the Underwriters to exceed 5% of the number of shares
offered hereby.

The Common Stock has been approved for listing on the New York Stock
Exchange subject to notice of issuance. To satisfy one of the requirements for
listing of the Common Stock on the New York Stock Exchange, the Underwriters
have undertaken to sell lots of 100 or more shares to a sufficient number of
persons to establish a minimum of 2,000 round lot beneficial holders after the
Offering.

Prior to the Offering, there has been no public market for the Common
Stock. The initial public offering price for the shares offered hereby will be
determined by negotiations among the Company, First Reserve and the
Representatives. In determining such price, consideration will be given to
various factors, including market conditions for initial public offerings, the
history of and prospects for the Company's business, the Company's past and
present operations, its past and present earnings and current financial
position, an assessment of the Company's management, the market of securities of
companies in businesses similar to those of the Company, the general condition
of the securities markets and other relevant factors. There can be no assurance
that the initial public offering price will correspond to the price at which the
Common Stock will trade in the public market subsequent to the Offering or that
an active trading market for the Common Stock will develop and continue after
the Offering.

The Representatives, on behalf of the Underwriters, may engage in
over-allotment, stabilizing transactions, syndicate covering transactions and
penalty bids in accordance with Regulation M under the Securities Exchange Act
of 1934 (the "Exchange Act"). Over-allotment involves syndicate sales in excess
of the offering size, which creates a syndicate short position. Stabilizing
transactions permit bids to purchase the underlying security so long as the
stabilizing bids do not exceed a specified maximum. Syndicate covering
transactions involve purchases of the Common Stock in the open market after the
distribution has been completed in order to cover syndicate short positions.
Penalty bids permit the Representatives to reclaim a selling concession from a
syndicate member when the Common Stock originally sold by such syndicate member
is purchased in a syndicate covering transaction to cover syndicate short
positions. Such stabilizing transactions, syndicate covering transactions and
penalty bids

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<PAGE>
may cause the price of the Common Stock to be higher than it would otherwise be
in the absence of such transactions. These transactions may be effected on the
New York Stock Exchange or otherwise and, if commenced, may be discontinued at
any time.

NOTICE TO CANADIAN RESIDENTS

RESALE RESTRICTIONS

The distribution of the Common Stock in Canada is being made only on a
private placement basis exempt from the requirement that the Company prepare and
file a prospectus with the securities regulatory authorities in each province
where trades of Common Stock are effected. Accordingly, any resale of the Common
Stock in Canada must be made in accordance with applicable securities laws which
will vary depending on the relevant jurisdiction, and which may require resales
to be made in accordance with available statutory exemptions or pursuant to a
discretionary exemption granted by the applicable Canadian securities regulatory
authority. Purchasers are advised to seek legal advice prior to any resale of
the Common Stock.

REPRESENTATIONS OF PURCHASERS

Each purchaser of Common Stock in Canada who receives a purchase
confirmation will be deemed to represent to the Company and the dealer from whom
such purchase confirmation is received that (i) such purchaser is entitled under
applicable provincial securities laws to purchase such Common Stock without the
benefit of a prospectus qualified under such securities laws, (ii) where
required by law, that such purchaser is purchasing as principal and not as
agent, and (iii) such purchaser has reviewed the text above under "Resale
Restrictions".

RIGHTS OF ACTION (ONTARIO PURCHASERS)

The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
section 32 of the Regulation under the SECURITIES ACT (Ontario). As a result,
Ontario purchasers must rely on other remedies that may be available, including
common law rights of action for damages or rescission or rights of action under
the civil liability provisions of the U.S. federal securities laws.

ENFORCEMENT OF LEGAL RIGHTS

All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be possible
for Canadian purchasers to effect service of process within Canada upon the
issuer or such persons. All or a substantial portion of the assets of the issuer
and such persons may be located outside of Canada and, as a result, it may not
be possible to satisfy a judgment against the issuer or such persons in Canada
or to enforce a judgment obtained in Canadian courts against such issuer or
persons outside of Canada.

NOTICE TO BRITISH COLUMBIA RESIDENTS

A purchaser of Common Stock to whom the SECURITIES ACT (British Columbia)
applies is advised that such purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
Common Stock acquired by such purchaser pursuant to this offering. Such report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from the Company. Only one
such report must be filed in respect of Common Stock acquired on the same date
and under the same prospectus exemption.

TAXATION AND ELIGIBILITY FOR INVESTMENT

Canadian purchasers of Common Stock should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the Common
Stock in their particular circumstances and with respect to the eligibility of
the Common Stock for investment by the purchaser under relevant Canadian
legislation.

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<PAGE>
LEGAL MATTERS

The validity of the shares of Common Stock offered hereby will be passed on
for the Company by Weil, Gotshal & Manges LLP, Houston, Texas and for the
Underwriters by Baker & Botts, L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of the Company as of December 31,
1996 and for the period from December 30, 1996 (date of incorporation) to
December 31, 1996, the combined financial statements of the Predecessor as of
December 31, 1995 and for each of the years in the three-year-period ended
December 31, 1996 and the statement of revenues and direct operating expenses of
certain properties acquired by the Predecessor for the eleven month period ended
November 30, 1994 have been audited by Deloitte & Touche LLP, independent
auditors, as stated in their reports appearing herein, and are included in
reliance upon the reports of such firm given upon their authority as experts in
accounting and auditing.

The reserve reports and estimates of the Company's net proved oil and
natural gas reserves included herein have, to the extent described herein, been
prepared by DeGolyer and Netherland, Sewell. Summaries of these estimates and
the audit letters of DeGolyer and Netherland, Sewell have been included in this
Prospectus as Appendix A in reliance upon such firms as experts with respect to
such matters.

AVAILABLE INFORMATION

As a result of the Offering, the Company will be subject to the
informational requirements of the Securities Exchange Act of 1934, as amended,
and in accordance therewith will file reports and other information with the
Commission. The reports and other information filed by the Company with the
Commission can be inspected and copies can be obtained at the public reference
facilities maintained by the Commission at Judiciary Plaza, Room 1024, 450 Fifth
Street, N.W., Washington, D.C. 20549, and at the Regional Offices of the
Commission at 7 World Trade Center, New York, New York 10048 and Northwestern
Atrium Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661.
Copies of such material also can be obtained from the Public Reference Section
of the Commission, 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed
rates. In addition, the Commission maintains a site on the World Wide Web at
http://www.sec.gov that contains reports, proxy and information statements and
other information regarding registrants that file electronically with the
Commission.

The Company has filed with the Commission a Registration Statement on Form
S-1 under the Securities Act with respect to the Common Stock offered hereby.
This Prospectus does not contain all of the information set forth in the
Registration Statement, certain portions of which are omitted as permitted by
the rules and regulations of the Commission. Such additional information may be
obtained at the locations listed above. Statements made in this Prospectus
concerning the contents of any contract, agreement or other document filed as an
exhibit to the Registration Statement are summaries of the terms of such
contract, agreement or document and are not necessarily complete. Reference is
made to each such exhibit for a more complete description of the matters
involved.

The Company intends to furnish its stockholders with annual reports
containing audited financial statements and an opinion expressed by independent
auditors and with quarterly reports for the first three quarters of each fiscal
year containing unaudited summary financial information.

80
<PAGE>
GLOSSARY

The following are definitions of certain terms used in this Prospectus.

BBL. One barrel of crude oil, condensate or other liquids equal to 42 U.S.
gallons.

BCF. Billion cubic feet.

BCFE. Billion cubic feet of natural gas equivalent.

BTU. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 degrees Fahrenheit to 59.5
degrees Fahrenheit under specific conditions.

DEVELOPED ACREAGE. The number of acres which are allocated or assignable
to producing wells or wells capable of production.

DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.

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

FARMOUT. An assignment of an interest in a drilling location and related
acreage conditional upon the drilling of a well or the establishment of
production on that location. The assignor usually retains an overriding royalty
interest or a working interest after payout in the lease.

FINDING COSTS. Expressed in terms of dollars per Mcfe, calculated by
dividing the amount of total capital expenditures for oil and gas activities by
the amount of estimated net proved reserves added during the same period
(including the effect on proved reserves of reserve revisions).

GROSS ACRES OR GROSS WELLS. The number of acres or wells in which the
Company has a working interest.

LEASE OPERATING EXPENSE. Costs incurred to operate and maintain wells and
related equipment and facilities including applicable operating costs of support
equipment and facilities and other costs of operating and maintaining those
wells and related equipment and facilities.

MBBL. One thousand barrels.

MCF. One thousand cubic feet.

MCFE. One thousand cubic feet of natural gas equivalent.

MMBBL. One million barrels.

MMBTU. One million Btus.

MMCF. One million cubic feet.

MMCFE. One million cubic feet of natural gas equivalent.

NATURAL GAS EQUIVALENT. Cubic feet of natural gas equivalent, determined
using the ratio of one Bbl of crude oil, condensate or natural gas liquids to
six Mcf of natural gas.

NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.

NET PROFITS INTEREST. An interest in an oil and gas property entitling the
owner to a share of the gross revenues from oil and gas production less all
operating, production, development, transportation, transmission and marketing
expenses, production, sales and ad valorem taxes attributable to such
production.

OVERRIDING ROYALTY INTEREST. A royalty interest which is carved out of a
lessee's working interest under an oil and gas lease.

PRODUCTION PAYMENT. A share of the oil or natural gas produced from a
specified tract of land, free of the costs of production at the surface,
terminating when a specified sum from the sale of such oil or natural gas has
been realized.

81
<PAGE>
PRODUCTIVE WELL. A well that is producing oil and gas or that is capable
of production.

PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.

PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered from completion intervals currently open in existing wells and able to
produce to market.

PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids 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 UNDEVELOPED RESERVES. Proved 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.

PV-10 RESERVE VALUE. The pre-tax present value, discounted at 10% per
annum, of future net cash flows from estimated proved reserves, calculated
holding prices and costs constant at amounts in effect on the date of the
estimate (unless such prices or costs are subject to change pursuant to
contractual provisions). The difference between the PV-10 Reserve Value and the
standardized measure of discounted future net cash flows is the present value of
income taxes applicable to such future net cash flows.

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

RESERVE LIFE INDEX. Calculated by dividing year-end proved reserves by
annual production for the most recent year.

ROYALTY INTEREST. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.

SPUD. To start (or restart) the drilling of a new well.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The present
value, discounted at 10% per annum, of future net cash flows from estimated
proved reserves, calculated holding prices and costs constant at amounts in
effect on the date of the estimate (unless such prices or costs are subject to
change pursuant to contractual provisions) and in all instances in accordance
with the Commission's rules for inclusion of oil and gas reserve information in
financial statements filed with the Commission.

TCF. One trillion cubic feet.

TERM OVERRIDING ROYALTY INTEREST. An overriding royalty interest with a
fixed duration.

UNDEVELOPED ACREAGE. Lease acreage on which wells have not been
participated in or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether such acreage contains
proved reserves.

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

WORKING INTEREST. A cost bearing interest which gives the owner the right
to drill, produce and conduct oil and gas operations on the property, as well as
a right to a share of production therefrom.

WORKOVER. Operations on a producing well to restore or increase
production.

82
<PAGE>
INDEX TO FINANCIAL STATEMENTS

PAGE
----

Independent Auditors' Report................... F-2

Combined and Consolidated Balance
Sheets as of December 31, 1995 and
1996, respectively........................... F-3

Combined Statements of Income for the
years ended December 31, 1994, 1995
and 1996..................................... F-4

Combined and Consolidated Statements
of Stockholder's Equity for the
years ended December 31, 1994, 1995
and 1996 and the period from
December 30, 1996 (date of
incorporation) to December 31,
1996, respectively........................... F-5

Combined and Consolidated Statements
of Cash Flows for the years ended
December 31, 1994, 1995 and 1996
and the period from December 30,
1996
(date of incorporation) to December
31, 1996, respectively....................... F-6

Notes to the Combined and
Consolidated Financial
Statements................................... F-7

Consolidated Balance Sheets as of
December 31, 1996 and March 31,
1997 (Unaudited)............................. F-22

Combined and Consolidated Statements
of Income for the three months
ended
March 31, 1996 and 1997,
respectively (Unaudited)..................... F-23

Consolidated Statement of
Stockholders' Equity for the three
months ended
March 31, 1997 (Unaudited)................... F-24

Combined and Consolidated Statements
of Cash Flows for the three months
ended March 31, 1996 and 1997,
respectively (Unaudited)..................... F-25

Notes to the Combined and
Consolidated Financial Statements
(Unaudited).................................. F-26

Independent Auditors' Report................... F-28

Statement of Revenues and Direct
Operating Expenses of the
Properties Acquired by Tenneco
Ventures Corporation from Pennzoil
Exploration and Production
Corporation and Pennzoil Petroleum
Company for the eleven months ended
November 30, 1994........................... F-29

Notes to the Statement of Revenues
and Direct Operating Expenses............... F-30

F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders of
Domain Energy Corporation

We have audited the accompanying consolidated balance sheet of Domain Energy
Corporation and subsidiaries (the "Company"), the Successor, as of December 31,
1996 and the related statement of stockholder's equity and cash flows from
December 30, 1996 (date of incorporation) to December 31, 1996. We have also
audited the accompanying combined balance sheet of Tenneco Ventures Corporation
and Tenneco Gas Production Corporation (the "Tenneco Entities"), the
Predecessor, as of December 31, 1995 and the related combined statements of
income, stockholder's equity and cash flows for each of the three years in the
period ended December 31, 1996. 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, such financial statements present fairly, in all material
respects, the consolidated financial position of the Company and its
subsidiaries as of December 31, 1996 and the combined financial position of the
Tenneco Entities as of December 31, 1995 and the combined results of their
operations and their combined cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted accounting
principles.

DELOITTE & TOUCHE LLP

Houston, Texas
April 3, 1997 (June 20, 1997 as to Note 7)

F-2
<PAGE>
DOMAIN ENERGY CORPORATION
COMBINED AND CONSOLIDATED BALANCE SHEETS
(NOTE 1)
(IN THOUSANDS, EXCEPT SHARE DATA)

AS OF DECEMBER 31,
---------------------------
PREDECESSOR SUCCESSOR
1995 1996
------------ -------------
ASSETS
Cash and cash equivalents............ $ -- $ 36
Restricted certificate of deposit.... -- 8,000
Accounts receivable.................. 13,219 19,456
IPF Program notes receivable, current
portion............................ 2,247 7,874
Prepaid and other current assets..... 1,608 1,525
------------ -------------
Total current assets............ 17,074 36,891
IPF Program notes receivable......... 5,744 13,836
Oil and natural gas properties, full
cost method.......................... 137,975 66,176
Less: Accumulated depreciation,
depletion and amortization........... (26,251) --
Investments and other assets......... 2,554 5,526
------------ -------------
Total assets.................... $137,096 $ 122,429
============ =============
LIABILITIES
Accounts payable..................... $ 11,265 $ 14,018
Accrued expenses..................... 48 42
Current maturities of long-term
debt............................... -- 24,900
------------ -------------
Total current liabilities....... 11,313 38,960
Long-term debt....................... -- 54,512
Deferred income taxes................ 12,379 --
Parent advances...................... 112,832 --
------------ -------------
Total liabilities............... 136,524 93,472
Minority interest.................... -- 380
Commitments and contingencies

STOCKHOLDER'S EQUITY

Common stock:
Predecessor -- $5.00 par value,
400 shares authorized, issued and
outstanding at December 31, 1995.
Successor -- $.01 par value,
15,080,000 shares authorized and
7,177,681v issued and outstanding
at December 31, 1996........... $ 2 $ 72
Additional paid-in capital........... -- 28,505
Retained earnings.................... 570 --
------------ -------------
Total stockholder's equity...... 572 28,577
------------ -------------
Total liabilities and
stockholder's equity............ $137,096 $ 122,429
============ =============

The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-3
<PAGE>
DOMAIN ENERGY CORPORATION
COMBINED STATEMENTS OF INCOME
(IN THOUSANDS)

PREDECESSOR
-------------------------------
YEAR ENDED DECEMBER 31,
-------------------------------
1994 1995 1996
--------- --------- ---------
REVENUES:
Oil and natural gas sales............... $ 5,340 $ 34,877 $ 52,274
IPF Activities.......................... 1,417 2,356 4,369
Other................................... 283 414 (413)
--------- --------- ---------
Total revenues................ 7,040 37,647 56,230
--------- --------- ---------
EXPENSES:
Lease operating......................... 1,790 7,980 10,207
Production and severance taxes.......... 18 710 1,340
Depreciation, depletion and
amortization.......................... 3,101 22,692 24,920
General and administrative.............. 52 2,780 3,361
Corporate overhead allocation........... 944 2,627 4,827
--------- --------- ---------
Total operating expenses...... 5,905 36,789 44,655
Income from operations.................. 1,135 858 11,575
Interest expense........................ -- -- 150
--------- --------- ---------
Income before income taxes.............. 1,135 858 11,425
Income tax provision.................... 735 351 4,394
--------- --------- ---------
Net income.............................. $ 400 $ 507 $ 7,031
========= ========= =========

The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-4
<PAGE>
DOMAIN ENERGY CORPORATION
COMBINED AND CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN THOUSANDS)

<TABLE>
<CAPTION>
PREDECESSOR
--------------------------------------------------------
ADDITIONAL RETAINED TOTAL
COMMON PAID IN EARNINGS STOCKHOLDER'S
STOCK CAPITAL (DEFICIT) EQUITY
------ ---------- -------- --------------
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1994.............. $ 2 $ -- $ (337) $ (335)
Net income.............................. -- -- 400 400
------ ---------- -------- --------------
Balance at December 31, 1994............ 2 -- 63 65
Net income.............................. -- -- 507 507
------ ---------- -------- --------------
Balance at December 31, 1995............ 2 -- 570 572
Net income.............................. -- -- 7,031 7,031
------ ---------- -------- --------------
Balance at December 31, 1996
(prior to the Acquisition)............ $ 2 $ -- $ 7,601 $ 7,603
====== ========== ======== ==============

SUCCESSOR
--------------------------------------------------------
ADDITIONAL TOTAL
COMMON PAID IN RETAINED SHAREHOLDER'S
STOCK CAPITAL EARNINGS EQUITY
------ ---------- -------- --------------
Balance at December 30, 1996 (date of
incorporation)........................ $-- $ -- $ -- $--
Issuance of Common Stock, net of
costs................................. 72 27,505 -- 27,577
Issuance of detachable stock options.... -- 1,000 -- 1,000
------ ---------- -------- --------------
Balance at December 31, 1996............ $ 72 $ 28,505 $ -- $ 28,577
====== ========== ======== ==============
</TABLE>
The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-5
<PAGE>
DOMAIN ENERGY CORPORATION
COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
PREDECESSOR SUCCESSOR
---------------------------------- ------------------------
FOR THE PERIOD FROM
YEAR ENDED DECEMBER 31, DECEMBER 30, 1996
---------------------------------- (DATE OF INCORPORATION)
1994 1995 1996 TO DECEMBER 31, 1996
---------- ---------- ---------- ------------------------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.............................. $ 400 $ 507 $ 7,031 $--
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation, depletion and
amortization..................... 3,101 22,692 24,920 --
Deferred income taxes.............. 9,586 883 6,702 --
Minority interest.................. -- -- 380 --
Allowance for doubtful IPF
investments...................... -- -- 437
Changes in operating assets and
liabilities:
Increase in accounts receivable.... (713) (6,731) (7,584) --
Decrease (increase) in prepaid and
other current assets............. (441) (956) 83 --
Increase (decrease) in accounts payable
and accrued expenses.................. (446) 3,538 2,584 --
---------- ---------- ---------- -------------
Net cash provided by operating
activities............................ 11,487 19,933 34,553 --

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of the Tenneco Entities..... -- -- -- (96,164)
Purchase of restricted certificate of
deposit............................... -- -- -- (8,000)
Investment in oil and natural gas
properties............................ (85,433) (44,118) (32,023) --
Proceeds from sale of oil and gas
properties............................ -- 8,275 1,546 --
IPF Program investments of capital
(notes receivable).................... (3,315) (6,606) (19,045) --
IPF Program return of capital (notes
receivable)........................... 3,507 2,638 4,618 --
Investment and other assets............. (1,428) 83 (2,425) --
---------- ---------- ---------- -------------
Net cash used in investing activities... (86,669) (39,728) (47,329) (104,164)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from debt borrowings........... -- -- 6,968 73,200
Repayment of debt borrowings............ -- -- (756) --
Advances from Parent, net............... 85,014 8,328 6,564 --
Issuance of common stock................ -- -- -- 31,000
---------- ---------- ---------- -------------
Net cash provided by financing
activities............................ 85,014 8,328 12,776 104,200
Increase (decrease) in cash and cash
equivalents........................... 9,832 (11,467) -- --
Cash and cash equivalents, beginning of
period................................ 1,635 11,467 -- --
---------- ---------- ---------- -------------
Cash and cash equivalents, end of period
(Predecessor -- before Acquisition)... $ 11,467 $ -- $ -- $ 36
========== ========== ========== =============
</TABLE>
The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-6
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BASIS OF PRESENTATION AND NATURE OF OPERATIONS

For the years ended December 31, 1994 and 1995 and for the period from
January 1, 1996 through December 11, 1996, Tenneco Ventures Corporation
("Ventures") and Tenneco Gas Production Corporation ("Production" and, together
with Ventures, the "Tenneco Entities") were indirect subsidiaries of Tenneco,
Inc. ("Tenneco"). As a result of a merger between Tenneco and a subsidiary of El
Paso Natural Gas Company ("El Paso"), Ventures and Production became wholly
owned indirect subsidiaries of El Paso for the period from December 12, 1996 to
December 31, 1996. On December 31, 1996, Domain Energy Corporation ("Domain")
acquired all of the outstanding common stock of Ventures and Production (the
"Acquisition"). Domain was incorporated in Delaware in December 1996 to acquire
such common stock and had no operations prior to the Acquisition.

Unless otherwise indicated, references to the Company are to Domain and its
subsidiaries at and subsequent to December 31, 1996 and to the combined
activities of the Tenneco Entities prior to December 31, 1996. References to the
Parent are to Tenneco or its affiliates prior to December 11, 1996 and to El
Paso from December 12, 1996 to December 31, 1996.

The Company was capitalized on December 31, 1996 with the issuance of
7,177,681 shares of common stock for $30.0 million and borrowings of $66.2
million under its credit facilities. The Company completed the Acquisition for a
total cash purchase price of approximately $96.2 million and the assumption of
liabilities of approximately $16.8 million. The Company did not assume the
liability of $124.1 million due to the parent of the Tenneco Entities. The
Company has accounted for the Acquisition using the purchase method of
accounting. The assets and liabilities of the Tenneco Entities have been
recorded in the Company's balance sheet at December 31, 1996 at their estimated
fair market values, summarized as follows (in thousands):

ASSETS:
Accounts receivable -- trade.... $ 19,456
IPF Program notes receivable.... 21,710
Oil and gas properties.......... 66,176
Other assets.................... 5,658
----------
Total assets............... $ 113,000
==========
LIABILITIES:
Accounts payable................ (10,624)
Long-term debt.................. (6,212)
----------
Total liabilities.......... $ (16,836)
==========

The financial statements of the Tenneco Entities at December 31, 1995 and
for each of the years ended December 31, 1994, 1995 and 1996 have been combined
to reflect their combined historical financial position and historical results
of operations.

The following unaudited pro forma summary presents the consolidated results
of operations of the Company for the years ended December 31, 1995 and 1996 as
if the Acquisition had occurred at the beginning of 1995 (in thousands):

1995 1996
--------- ---------
Revenues................................ $ 37,647 $ 56,230
Net income.............................. $ 3,024 $ 9,714

F-7
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Program") pursuant to which it invests in oil and natural gas reserves through
the acquisition of term overriding royalty interests.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION AND COMBINATION -- The consolidated balance
sheet at December 31, 1996 includes the accounts of the Company and its
majority-owned subsidiaries. The Company sponsored and managed two oil and gas
investment programs for unaffiliated institutional investors (the "Funds"). The
Company has a 10% interest in one program and a 30% interest in the other. The
Company and the investors each own direct undivided interests in oil and gas
properties. The Company accounts for its interests in the Funds using the pro
rata method of consolidation.

The Company owns 35% of the voting capital stock of Michigan Production
Company L.L.C. ("MPC") and accounts for MPC using the equity method of
accounting. The Company also owns 28% of the voting capital stock of Michigan
Energy Company, L.L.C. ("MEC"), which is accounted for using the equity method
of accounting. Both equity investments were acquired in 1996.

The following presents combined summary information for MPC and MEC (in
thousands):

DECEMBER 31,
1996
------------
Current assets....................... $ 1,654
Non-current assets................... 35,601
Current liabilities.................. 6,640
Non-current liabilities.............. 27,587

YEAR ENDED
DECEMBER 31,
1996
------------
Revenues............................. $ 690
Operating expenses................... 953
Net income........................... (520)

The combined financial statements of the Tenneco Entities include their
combined accounts and the combined accounts of their majority-owned
subsidiaries. All significant intercompany accounts and transactions have been
eliminated.

OIL AND GAS PROPERTIES -- Investments in oil and gas properties are
accounted for using the full cost method of accounting. All costs associated
with the acquisition, exploration, exploitation and development of oil and gas
properties are capitalized. General and administrative costs of $1.6 million,
$2.1 million and $2.6 million were included in capitalized costs for the years
ended December 31, 1994, 1995 and 1996, respectively. Such capitalized costs
include payroll and other related costs attributable to the Company's
acquisition and exploration activities. Costs related to production,
development, and the IPF program are expensed within the presented year and not
capitalized.

Oil and gas properties are amortized using the unit-of-production method
using estimates of proved reserve quantities. Investments in unproved properties
are not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. If the results of the assessment indicate
that the properties are impaired, the amount of impairment is added to the
proved oil and gas property costs to be amortized. The amortizable base includes
future development costs and, where significant, dismantlement, restoration, and
abandonments costs, net of estimated salvage values. The depletion rate per Mcfe
for the years ended December 31, 1994, 1995 and 1996 was $1.03, $1.08 and $1.01,
respectively.

Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between

F-8
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
capitalized costs and proved reserves. Abandonments of properties are accounted
for as adjustments of capitalized costs with no loss recognized.

In addition, the total capitalized costs of oil and gas properties are
subject to a "ceiling test," which limits such costs to the estimated present
value, discounted at a 10% interest rate, of future net cash flows from proved
reserves, based on current economic and operating conditions, plus the cost of
unproved prospects. If capitalized costs exceed this limit, the excess is
charged to depreciation, depletion and amortization.

INDEPENDENT PRODUCER FINANCE PROGRAM -- Through its IPF Program, the
Company acquires term overriding royalty interests in oil and gas properties
owned by independent producers. Because the funds advanced to a producer for
these interests are repaid from an agreed upon share of cash proceeds from the
sale of production until the amount advanced plus interest is paid in full, the
Company accounts for the term overriding royalty interests as notes receivable.
Under this accounting method, the Company recognizes only the interest income
portion of payments received from a producer as revenues on its income
statement. The remaining cash receipts are recorded as a reduction in notes
receivable on the Company's balance sheet and as IPF Program return of capital
on the Company's statement of cash flows. The Company records an impairment for
its investments on a case-by-case basis when it determines repayment to be
doubtful.

PARENT ADVANCES -- Prior to the Acquisition, Parent advances to the Company
for net working capital and capital expenditure requirements are recorded as
non-current liabilities on the combined balance sheet. The Parent did not charge
the Company any interest expense on the funds utilized by the Company.

INCOME TAXES -- Through December 31, 1996, the Company's taxable income is
included in a consolidated United States income tax return with the Parent. The
intercompany tax allocation policy between the Company and the Parent provided
that each member of the consolidated group compute a provision for income taxes
on a separate return basis. The Company records its income taxes utilizing an
asset and liability approach which requires recognition of deferred tax assets
and liabilities for the expected future tax consequences of temporary
differences between the book carrying amounts and the tax basis of assets and
liabilities. All current amounts due to or from the Parent are included in
Parent advances on the combined balance sheet.

OIL AND GAS HEDGING ACTIVITIES -- The Company periodically uses derivative
financial instruments to manage price risks related to oil and natural gas sales
and not for speculative purposes. For book purposes, gains and losses related to
the hedging of anticipated transactions are recognized as income when the hedged
transaction occurs.

The Company primarily utilizes price swap agreements with major energy
companies to accomplish its hedging objectives. The price swap agreements
generally provide for the Company to receive or make counter-party payments on
the differential between a fixed price and a variable indexed price. Total oil
and natural gas sales hedged during the years ended December 31, 1996 and 1995
were 258,710 Bbls and 16,025 MMcf and 65,840 Bbls and -0-MMcf, respectively.
There were no hedging transactions in 1994. Gains (losses) realized by the
Company under such hedging arrangements, and reported as an increase (reduction)
of revenues, were ($10.5 million) and $0.2 million for the years ended December
31, 1996 and 1995, respectively. The following table sets forth the Company's
open hedging contracts for oil and natural gas under various price swap
agreements with major energy companies as of December 31, 1996:

<TABLE>
<CAPTION>
CRUDE OIL NATURAL GAS
------------------------------ ----------------------------
WEIGHTED AVERAGE WEIGHTED AVERAGE
BBLS FIXED SALES PRICE MMBTU FIXED SALES PRICE
--------- ------------------ ------ ------------------
<S> <C> <C> <C> <C>
Jan 1997 -- Dec 1997............ 244,540 $17.37 4,270 $ 2.58
Jan 1998 -- Dec 2000............ 442,550 $18.37 -- --
</TABLE>
F-9
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REVENUE RECOGNITION -- The Company recognizes oil and gas revenue from its
interests in producing wells as oil and gas is sold from those wells. Oil and
gas sold in production operations is not significantly different from the
Company's share of production. The Company recognizes financing revenues from
its producer financing activities using the effective interest rate method.

The Company utilizes the sales method to account for gas production volume
imbalances. Under this method, income is recorded based on the Company's net
revenue interest in production taken for delivery. Management does not believe
that the Company had any material natural gas imbalances at December 31, 1996 or
1995.

FINANCIAL INSTRUMENTS -- The Company's financial instruments consist of
cash, accounts and notes receivable, payables, long-term debt and oil and
natural gas commodity hedges. The carrying amount of cash, accounts receivable
and payables approximates fair value because of the short-term nature of these
items. Based on current industry and other conditions, management believes that
the carrying value of its IPF Program notes receivable approximates, at a
minimum, their fair value. The carrying value of long-term debt approximates
fair value because the individual borrowings bear interest at floating market
rates. Assuming a market price based on the twelve-month strip as of December
31, 1996, the Company's projected losses from these open hedge contracts were
approximately $2.7 million as of December 31, 1996. Considerable judgment is
required in developing these estimates and, accordingly, no assurance can be
given that the estimated values presented herein are indicative of amounts that
would be realized in a full market exchange.

USE OF ESTIMATES -- The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expenses during
the reporting periods. Actual results could differ from these estimates.
Significant estimates include depreciation, depletion and amortization of proved
producing oil and natural gas properties; estimates of proved oil and natural
gas reserve volumes; and discounted future net cash flows.

CONCENTRATION OF RISK -- Substantially all of the Company's accounts and
notes receivable result from oil and natural gas sales, joint interest billings
and lending activities to third parties in the oil and natural gas industry.
This concentration of customers, joint interest owners and borrowers may impact
the Company's overall credit risk in that these entities may be similarly
affected by changes in economic and other conditions.

STATEMENTS OF CASH FLOWS -- The statements of cash flows are presented
using the indirect method and consider all highly liquid investments with
maturities at the time of purchase of three months or less to be cash
equivalents.

Supplemental cash flow information may be summarized as follows (in
thousands):
<TABLE>
<CAPTION>
PREDECESSOR SUCCESSOR
---------------------------------- ---------
1994 1995 1996 1996
---------- ---------- ---------- ---------
<S> <C> <C> <C>
Interest expense paid................ $ -- $ -- $ 307 --
Income taxes paid to Parent.......... -- -- -- --
The Acquisition:
Total cash consideration........ $ -- $ -- $ -- $ 96,164
Fair value of assets acquired... -- -- -- 113,000
Liabilities assumed............. -- -- -- 16,836
</TABLE>
EMPLOYEE STOCK-BASED COMPENSATION -- In October 1995, Financial Accounting
Standards Board Statement No. 123, "Accounting for Stock Based Compensation"
("SFAS 123") was issued. Under SFAS No. 123, the Company is permitted to either
record expenses for stock options and other stock-based employee compensation
plans based on their fair value at the date of grant or to apply the existing
standard, Accounting Principles Board Opinion No. 25 ("APB 25") and recognize
compensation expense, if any, based on the intrinsic value of the equity
instrument at the measurement date. The Company has elected to

F-10
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
continue to follow APB 25. When applicable, the Company will disclose pro forma
net income and earnings per share computed as if the Company utilized SFAS 123.

3. NOTES RECEIVABLE -- INDEPENDENT PRODUCER FINANCING

At December 31, 1996 and 1995, the Company had total outstanding notes
receivable related to its IPF Program of $21.7 million and $8.0 million,
respectively. The notes receivable result from the Company's purchase of a
production payment in the form of a term overriding royalty interest in exchange
for an agreed upon share of revenues from identified properties until the amount
invested and a specified rate of return on investment is paid in full. During
1995 and 1996, the Company realized returns from the IPF Program of 20.0% and
17.7%, respectively. The weighted average returns expected by the Company on the
notes receivable outstanding at December 31, 1995 and December 31, 1996 were
26.5% and 20.9%, respectively. While the independent producer's obligation to
deliver such revenues is nonrecourse to the producer, management believes that
the Company's overriding royalty interest constitutes a property interest and
therefore, such property interest and the underlying oil and gas reserves
effectively serves as security for the notes receivable. Based on reserve data
available, the Company has estimated that $7.9 million and $2.2 million of notes
receivable at December 31, 1996 and 1995 will be repaid in the next twelve
months and has classified such amounts as current assets.

In fiscal 1996, the Company established an allowance for doubtful accounts
of approximately $0.4 million related to its IPF Program, which is the balance
of such account at December 31, 1996. No other allowance activity occurred
during the three years ended December 31, 1996. The allowance for doubtful
accounts was zero for the years ended December 31, 1994 and 1995. Based on the
December 31, 1996 notes receivable balance, expected principal payments in each
of the next five years are as follows (in thousands):

1997.................................... $ 7,874
1998.................................... $ 4,689
1999.................................... $ 2,902
2000.................................... $ 1,995
2001.................................... $ 1,527

4. UNEVALUATED PROPERTY

Oil and natural gas properties not subject to amortization consist of the
cost of undeveloped leaseholds, exploratory and developmental wells in progress,
and secondary recovery projects before the assignment of proved reserves. These
costs are reviewed periodically by management for impairment, with the
impairment provision included in the cost of oil and natural gas properties
subject to amortization. Factors considered by management in its impairment
assessment include drilling results by the Company and other operators, the
terms of oil and gas leases not held by production, production response to
secondary recovery activities and available funds for exploration and
development. The following table summarizes the cost of the properties not
subject to amortization for the year cost was incurred (in thousands):

DECEMBER 31,
--------------------
1995 1996
--------- ---------
Year cost incurred:
Remainder
1993....................... $ 4,219 $ --
1994....................... 23,364 --
1995....................... 10,334 --
1996....................... -- 12,662
--------- ---------
$ 37,917 $ 12,662
========= =========

F-11
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. LONG-TERM DEBT

At December 31, 1995 and 1996, notes payable and long-term debt consisted
of the following (in thousands):

DECEMBER 31,
---------------------
1995 1996
--------- ----------
Revolving Credit Facility............ $ -- $ 61,200
Indebtedness to Fund VII............. -- 7,000
IPF Company Credit Facility.......... -- 11,212
--------- ----------
Long-term debt....................... $ -- $ 79,412
Less current maturities.............. -- (24,900)
--------- ----------
$ -- $ 54,512
========= ==========

REVOLVING CREDIT FACILITY -- In connection with the Acquisition, the
Company entered into a $65.0 million revolving credit facility maturing on
December 31, 1999 (the "Revolving Credit Facility") with a group of banks led by
The Chase Manhattan Bank. The Revolving Credit Facility is secured by
approximately 80% of the aggregate value of the Company's oil and gas properties
and substantially all of the Company's other property (other than IPF Program
related properties), including the capital stock of Ventures and Production and
is also guaranteed by Ventures and Production. Amounts available under the
Revolving Credit Facility are subject to a borrowing base with scheduled
redeterminations every six months (and such other redeterminations as the lender
may elect to perform) by the lenders at the lenders' sole discretion and in
accordance with their customary practices and standards in effect from time to
time for reserve-based loans to borrowers similar to the Company. The borrowing
base under the Revolving Credit Facility at December 31, 1996 was $65.0 million.
On December 31, 1997, the Company is required to reduce its outstanding
indebtedness under the Revolving Credit Facility to $43.3 million. In addition,
if at the end of any fiscal quarter of the Company during 1997 the amount then
outstanding thereunder exceeds $43.3 million (as such amount may be adjusted
from time to time pursuant to the Revolving Credit Facility), the Company will
be obligated to prepay the outstanding indebtedness thereunder in an amount
equal to 100% of the Company's "excess cash flow" (as defined therein) for such
fiscal quarter. Excess cash flow is defined to include a portion of the net
proceeds to the Company of the Offering.

Absent a default or an event of default, borrowings under the Revolving
Credit Facility accrue interest at LIBOR plus a margin of 1.50% to 2.50% per
annum depending on the total amount outstanding or, at the option of the
Company, at the greater of (i) the prime rate and (ii) the federal funds
effective rate plus 0.50%, plus a margin of 0.50% to 1.50% depending on the
total amount outstanding. The Company also incurs a quarterly commitment fee
ranging from 0.375% to 0.50% per annum on the average unused portion of the
lenders' aggregate commitment depending on the total amount outstanding. The
interest rate on the amounts outstanding at December 31, 1996 was 9.75%.

The Revolving Credit Facility contains a number of covenants that, among
other things, restrict the ability of the Company to dispose of assets, incur
additional indebtedness, pay dividends, enter into certain investments or
acquisitions, repurchase or redeem capital stock, engage in mergers or
consolidations, or engage in certain transactions with subsidiaries and
affiliates and that will otherwise restrict corporate activities. In addition,
such facility requires the Company to maintain a specified minimum tangible net
worth and to comply with certain prescribed financial ratios. Further, under
such facility, an event of default is deemed to occur if any person, other than
the Company's officers, Fund VII or any other investment fund, the managing
general partner of which is First Reserve, becomes the beneficial owner,
directly or indirectly, of more than 40% of the outstanding shares of Common
Stock.

IPF COMPANY CREDIT FACILITY -- IPF Company, an indirect wholly-owned
subsidiary of the Company, has a $20.0 million revolving credit facility with
Compass Bank-Houston (the "IPF Company Credit

F-12
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Facility") pursuant to which it finances a portion of the IPF Program. The IPF
Company Credit Facility matures June 1, 1998 at which time all amounts owed
thereunder are due and payable. The IPF Company Credit Facility is secured by
substantially all of IPF Company's oil and gas term overriding royalty
interests, including the notes receivable generated therefrom. The borrowing
base under the facility as of March 31, 1997 was $18.0 million and is subject to
a scheduled redetermination by the lender every six months and such other
redeterminations as the lender may elect to perform each year. Absent a default
or an event of default (as defined therein), borrowings under the IPF Company
Credit Facility accrue interest at LIBOR plus a margin of 2.25% or, at the
option of the IPF Company, the prime rate published in THE WALL STREET JOURNAL.
The interest rate on the amounts outstanding as of December 31, 1996 was 7.81%.

The IPF Company Credit Facility restricts the ability of IPF Company to
dividend cash to its parent, Ventures, or otherwise advance cash to the Company.
At December 31, 1996, IPF Company net assets of approximately $10.0 million were
restricted.

INDEBTEDNESS TO FUND VII -- Prior to the Acquisition, Tennessee Gas
Pipeline Company ("TGPL"), the former wholly-owning parent of Ventures, was a
guarantor with respect to certain indebtedness (the "Michigan Senior Debt") of a
partnership formed to participate in a development project in Michigan in which
Ventures was at the time a general partner. In connection with the Acquisition,
the Company formed Domain Energy Guarantor Corporation ("Guarantor
Corporation"), for the sole purpose of assuming the obligations of TGPL under
such guaranty. As security for its obligations under the guaranty, Guarantor
Corporation purchased an $8.0 million certificate of deposit issued by the
lender in respect of the Michigan Senior Debt and assigned and pledged such
certificate to the lender.

To enable Guarantor Corporation to purchase the $8.0 million certificate
pledged as collateral for its guaranty of the Michigan Senior Debt, First
Reserve Fund VII, Limited Partnership ("Fund VII"), the Company's sole
stockholder at December 31, 1996, loaned Guarantor Corporation $8.0 million
evidenced by a Subordinated Promissory Note dated December 31, 1996 (the
"Note"). The full principal amount of the Note matures on December 31, 1999.
Interest accrues on the Note at a rate per annum equal to the interest rate per
annum earned by Guarantor Corporation on the $8.0 million certificate and is
payable quarterly. The obligations of Guarantor Corporation under the Note are
expressly made subordinate and subject in right of payment to the prior payment
in full of the Michigan Senior Debt. Pursuant to the terms of the Note, First
Reserve has the right to convert the Note into Common Stock. In accordance with
APB 14, $1.0 million of the Note has been reclassified from notes payable to
additional paid-in capital on the Company's financial statements. As a result of
the reclassification, the effective interest rate on the Note increases from
4.60% to 5.26%. The remaining $7.0 million of the Note has been classified as
current maturities of long-term debt in keeping with First Reserve's intent to
exercise its option to acquire Common Stock concurrent with consummation of the
Offering.

6. RELATED PARTY TRANSACTIONS

CORPORATE OVERHEAD ALLOCATION -- Prior to the Acquisition, the Company paid
an affiliate of the Parent for various administrative support services,
including treasury, legal, tax, human resources and administration. Allocations
were based on the Company's percentage of total assets as compared to the
Parent's total assets. Included in the 1996 allocation was approximately $2.0
million of costs that were directly related to severance payments, retention
bonuses and other costs associated with the merger of

F-13
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Tenneco with an affiliate of El Paso Natural Gas Company. Management of the
Company believes that the allocations were reasonable and approximate those
costs which would have been incurred from unrelated parties.

Prior to the Acquisition, the Parent also advanced various amounts to the
Company for working capital and capital expenditure requirements. The Parent did
not charge the Company any interest expense on the funds utilized by the
Company. The average amounts of advances outstanding from the Parent were
approximately $31.6 million, $107.7 million and $118.5 million for the years
ended December 31, 1994, 1995 and 1996, respectively. A summary of the activity
in the advances from Parent account follows (in thousands):

1994 1995 1996
---------- ---------- ------------
Beginning balance, January 1,........ $ 19,491 $ 104,504 $ 112,832
Cash advances, net................... 93,937 5,545 1,737
Corporate overhead allocation........ 944 2,627 4,827
Other allocations (accrued taxes).... (9,868) 156 4,734
Liability to Parent at the
Acquisition date not assumed by the
Company............................ -- -- (124,130)
---------- ---------- ------------
Ending balance, December 31.......... $ 104,504 $ 112,832 $ --
========== ========== ============

In connection with the Acquisition, the Company agreed to pay First Reserve
Corporation ("First Reserve"), the managing partner of Fund VII, a fee of
$500,000 for financial advisory services rendered in connection with the
Acquisition.

7. STOCKHOLDERS' EQUITY

COMMON STOCK -- As of June 20, 1997, the Company was authorized to issue up
to 25,000,000 shares of Common Stock, $.01 par value per share. All share
amounts in the financial statements have been retroactively restated to present
a 754-for-one stock split effected on June 20, 1997. As of December 31, 1996,
there were 7,177,681 shares of Common Stock issued and outstanding. Holders of
Common Stock are entitled to one vote for each share held and are not entitled
to cumulative voting for the purpose of electing directors and have no
preemptive or similar right to subscribe for, or to purchase, any shares of
Common Stock or other securities to be issued by the Company in the future.
Accordingly, the holders of more than 50% in voting power of the shares of
Common Stock voting generally for the election of directors will be able to
elect all of the Company's directors.

PREFERRED STOCK -- As of June 20, 1997, the Board of Directors was
authorized, without action by the holders of Common Stock, to issue up to
5,000,000 shares of preferred stock, $.01 par value per share (the "Preferred
Stock"), in one or more series, to establish the number of shares to be included
in each such series and to fix the designations, preferences, relative,
participating, optional and other special rights of the shares of each such
series and the qualifications, limitations and restrictions thereof. Such
matters may include, among others, voting rights, conversion and exchange
privileges, dividend rates, redemption rights, sinking fund provisions and
liquidation rights that could be superior and prior to the Common Stock. As of
December 31, 1996, no shares of preferred stock were issued and outstanding.

F-14
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
relationship with the Company or its affiliates, singly or in combination,
Incentive Stock Options, Other Stock Options, Stock Appreciation Rights,
Restricted Stock, Purchase Stock, Dividend Equivalent Rights, Performance Units,
Performance Shares or Other Stock-Based Grants, in each case as such terms are
defined therein. The terms of any such grant will be determined by the
Compensation Committee and set forth in a separate grant agreement. The exercise
price will be at least equal to 100% of fair market value of the Common Stock on
the date of grant in the case of Incentive Stock Options and the exercise price
of Other Stock Options will be at least equal to 50% of fair market value of the
Common Stock on the date of grant, provided that options to purchase up to
433,546 shares of Common Stock may be granted with an exercise price equal to
$.01 per share, which is the par value of the Common Stock. Non-Qualified Stock
Options and Other Stock Options may be exercisable for up to ten years.

On February 21, 1997 (the "Grant Date"), the Company granted to the
officers of the Company, pursuant to separate Non-Qualified Stock Option
Agreements (collectively, as amended, the "Stock Option Agreements") between the
Company and each of such persons, options to purchase a total of 753,998 shares
of Common Stock under the Stock Purchase and Option Plan. In addition, the
Company has granted options to purchase an aggregate of 95,696 shares of Common
Stock to other employees of the Company. Under the terms of the Stock Option
Agreements, 50% of the options granted to each such person are designated as
time options (collectively, the "Time Options"), with an exercise price equal to
$4.18 per share, and 50% are designated as performance options (collectively,
the "Performance Options"), with an exercise price equal to $.01 per share. The
Time Options become exercisable as to 20% of the shares of Common Stock subject
thereto on the first anniversary of the Grant Date and are exercisable as to an
additional 20% of such shares upon each anniversary of the Grant Date
thereafter. The Performance Options become exercisable at any time following the
second anniversary of the Grant Date, when the Investment Return Hurdle (as such
term is defined) is met; provided that the Performance Options become
exercisable as to 100% of the shares of Common Stock subject thereto on the
ninth anniversary of the Grant Date.

MANAGEMENT INVESTOR SUBSCRIPTION AGREEMENTS AND RELATED TRANSACTIONS -- On
February 21, 1997, each of the Company's officers (the "Management Investors")
entered into a Management Investor Subscription Agreement with the Company
pursuant to which the Management Investors purchased an aggregate of 390,307
shares of Common Stock at $4.18 per share. To facilitate such purchases, the
Company loaned the Management Investors an aggregate of approximately $546,000.
All such indebtedness of such persons accrues interest at the rate of 8% per
annum, payable semiannually; provided that each Management Investor may elect to
satisfy his or her semiannual interest payment obligation by increasing the
principal amount of the indebtedness owed to the Company by the amount of
interest otherwise payable. As security for such loans made by the Company, each
Management Investor pledged to the Company, and granted a first priority
security interest in, the shares of Common Stock purchased by such Management
Investor pursuant to its respective Management Investor Subscription Agreement
and is required to pledge, and grant a first priority security interest in, all
other shares of Common Stock that each such person may subsequently acquire,
including, without limitation, upon exercise of options to purchase shares of
Common Stock. In addition, in April 1997, other employees of the Company
purchased 95,696 shares of Common Stock at an average price of $4.18 per share.

F-15
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

COMPENSATION EXPENSE -- For purposes of determining compensation expense
pursuant to APB 25, the measurement date for the stock options granted to
officers of the Company is December 31, 1996 as on that date each officer knew
the number of options (both Time Options and Performance Options) that they
would be granted, the number of shares that they would be entitled to receive
upon exercise of the options and the option exercise price. The measurement date
for other options granted and stock sold is the date of the grant or sale.
Compensation expense is calculated based on the difference in the proceeds that
the Company receives upon issuance of the stock and the estimated fair value of
the stock at the measurement date. The Company anticipates recognizing stock
compensation expense based on actual stock acquired and in accordance with the
vesting schedule of options granted as follows:

1997................................. $ 4,832,000
1998................................. $ 1,188,000
1999................................. $ 238,000
2000................................. $ 40,000
2001................................. $ 20,000
2002................................. $ 4,000

OPTION TO ACQUIRE COMMON STOCK -- Pursuant to the Subscription Agreement,
dated December 31, 1996 (the "First Reserve Subscription Agreement"), between
the Company and Fund VII, the Company granted to Fund VII an option (the "First
Reserve Option") to acquire 1,914,048 shares of Common Stock for an aggregate
purchase price of $8.0 million plus any cash interest payment on the Note (see
Note 5) actually received by Fund VII (the "Option Price"). The Option Price
could be paid by Fund VII (i) prior to the date on which the Note has been paid
in full, by delivery to the Company of the Note together with the payment in
cash of any principal or interest payments on the Note previously received by
Fund VII and (ii) after the date on which the Note has been paid in full, by
payment of the Option Price in cash. In connection with the Offering, the
Company and Fund VII have agreed to restructure the terms of the First Reserve
Option as set forth below.

The Company and Fund VII have agreed that concurrently with consummation of
the Offering, Fund VII will purchase at a price per share equal to the Price to
Public set forth on the cover page of this Prospectus, a number of shares of
Common Stock such that the aggregate purchase price paid by Fund VII for such
shares equals $8,681,000. The amount of $8,681,000 represents the sum of (i) the
outstanding principal balance of the Note plus estimated accrued interest
thereon through June 15, 1997 and (ii) $500,000 in cash to be paid by Fund VII.

In accordance with APB 14, $1.0 million of the Note, representing the
estimated fair value of the First Reserve Option, has been reclassified from
notes payable to additional paid-in capital. See Note 5.

8. INCOME TAXES

The provision for income taxes consists of the following (in thousands):

YEAR ENDED DECEMBER 31,
-------------------------------
1994 1995 1996
--------- --------- ---------
Federal:
Current......................... $ (7,082) $ (518) $ (2,965)
Deferred........................ 7,296 791 6,511
State:
Current......................... (1,769) (14) 657
Deferred........................ 2,290 92 191
--------- --------- ---------
Income tax expense................... $ 735 $ 351 $ 4,394
========= ========= =========

F-16
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table sets forth a reconciliation of the statutory federal
income tax with the Company's effective taxes allocated by the Parent (in
thousands):

1994 1995 1996
--------- --------- ---------
Income before income taxes........... $ 1,135 $ 858 $ 11,425
--------- --------- ---------
Income tax computed at statutory
rates.............................. $ 397 $ 300 $ 3,999
State taxes, net of federal
benefit............................ 338 54 551
Other................................ -- (3) (156)
--------- --------- ---------
Income tax expense................... $ 735 $ 351 $ 4,394
========= ========= =========

Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes.

The Company's deferred tax liability as of December 31, 1995 was
$12,379,000. This amount represents the temporary difference in the tax and book
basis of the Company's oil and natural gas properties and investments.

As of December 31, 1996, the Company had no deferred tax liability. As a
result of the Acquisition and the corresponding election made by El Paso and the
Company to step-up the tax basis in the assets acquired, there are no temporary
differences in the carrying amounts of assets and liabilities for financial
reporting and income tax purposes.

9. COMMITMENTS AND CONTINGENCIES

From time to time, the Company is a party to certain lawsuits and claims
arising in the ordinary course of business. While the outcome of lawsuits and
claims cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the Company's financial
condition, results of operations or cash flow.

401(K) PLAN -- Effective December 31, 1996, the Company has offered its
employees an employee 401(k) savings plan (the "401(k) Plan"). The 401(k) Plan
covers all employees and entitles each to contribute up to 15% of his or her
annual compensation subject to maximum limitations imposed by the Internal
Revenue Code. The 401(k) Plan allows for employer matching of up to 8% of the
employee's contributions based on years of participation in the plan, including
years of participation in the 401(k) plan previously offered by Tenneco.

10. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
QUARTER ENDED
------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1995 1995 1995 1995(1)
--------- -------- ------------- ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Revenues............................. $ 6,499 $ 7,546 $ 7,681 $ 15,921
Operating income (loss).............. (454) 418 (547) 1,441
Net income (loss).................... (287) 241 (336) 889

QUARTER ENDED
------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1996 1996 1996 1996(1)
--------- -------- ------------- ------------
(IN THOUSANDS)
Revenues............................. $16,143 $ 14,686 $13,531 $ 11,870
Operating income (loss).............. 4,096 6,126 2,047 (694)
Net income (loss).................... 2,754 3,855 982 (560)
</TABLE>
- ------------

(1) The fourth quarter 1996 includes $2.1 million of corporate overhead which is
$1.2 million greater than the average of the first three quarters. This
amount includes costs related to the merger between Tenneco and an affiliate
of El Paso.

F-17
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities."

CAPITALIZED COSTS -- Capitalized costs and accumulated depreciation,
depletion and amortization relating to the Company's oil and gas producing
activities, all of which are conducted within the continental United States, are
summarized below (in thousands):

YEAR ENDED DECEMBER 31,
---------------------
1995 1996
---------- ---------
Proved producing oil and gas
properties......................... $ 100,058 $ 53,514
Unevaluated properties............... 37,917 12,662
---------- ---------
137,975 66,176
Less: Accumulated depreciation,
depletion and amortization......... (26,251) --
---------- ---------
Net capitalized costs................ $ 111,724 $ 66,176
========== =========
Company's share of equity method
investee's net capitalized cost.... $ 17,815
---------

COSTS INCURRED -- Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below (in thousands):

YEAR ENDED DECEMBER 31,
-------------------------------
1994 1995 1996
--------- --------- ---------
Property acquisition costs:
Unproved........................ $ 1,967 $ 3,207 $ 732
Proved.......................... 63,234 15,186 7,781
Exploration costs.................... 15,121 23,677 12,126
Development costs.................... 4,883 7,834 7,506
--------- --------- ---------
Total costs incurred................. $ 85,205 $ 49,904 $ 28,145
========= ========= =========
Company's share of equity method
investee's cost incurred........... $ 17,978
---------

RESERVES -- Proved reserves are estimated quantities of 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.

Proved oil and natural gas reserve quantities and the related discounted
future net cash flows before income taxes for the periods presented are based on
estimates prepared by DeGolyer and MacNaughton, Netherland, Sewell & Associates,
Inc., and other third-party independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.

F-18
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below.

OIL, CONDENSATE AND NATURAL GAS LIQUIDS
(BBLS)
---------------------------------------
1994 1995 1996
----------- ------------ ------------
Proved developed and undeveloped reserves:
Beginning of year............... 419,253 4,109,442 2,197,181
Revisions of previous
estimates..................... (130,555) (704,308) 289,216
Purchases of oil and gas
properties.................... 3,713,694 1,713,328 8,152,514
Extensions and discoveries...... 190,050 179,224 180,286
Sales of oil and gas
properties.................... -- (2,676,505) (127,305)
Production...................... (83,000) (424,000) (563,831)
----------- ------------ ------------
End of year..................... 4,109,442 2,197,181 10,128,061
=========== ============ ============
Proved developed reserves at end of
year............................... 3,124,873 1,701,656 9,775,753
=========== ============ ============
Equity in proved reserves of equity
investee............................. 1,251,592
------------

NATURAL GAS (MCF)
-----------------------------------------
1994 1995 1996
------------ -------------- -----------
Proved developed and undeveloped reserves:
Beginning of year............... 10,073,576 73,398,877 82,682,380
Revisions of previous
estimates..................... (4,525,096) 5,769,806 (2,920,927)
Purchases of oil and gas
properties.................... 64,489,577 19,898,227 --
Extensions and discoveries...... 5,694,820 13,083,241 4,743,646
Sales of oil and gas
properties.................... -- (11,402,771) (3,218,665)
Production...................... (2,334,000) (18,065,000) (21,191,895)
------------ ------------ ------------
End of year..................... 73,398,877 82,682,380 60,094,539
============ ============ ============
Proved developed reserves at end of
year............................... 58,005,413 65,178,731 47,495,614
============ ============ ============
Equity in proved reserves of equity
investee............................. 21,243,379
------------

<TABLE>
<CAPTION>
TOTAL (MCFE)
--------------------------------------------
1994 1995 1996
------------ -------------- --------------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of year............... 12,589,094 98,055,529 95,865,466
Revisions of previous
estimates..................... (5,308,426) 1,543,958 (1,185,631)
Purchases of oil and gas
properties.................... 86,771,741 30,178,195 48,915,084
Extensions and discoveries...... 6,835,120 14,158,585 5,825,362
Sales of oil and gas
properties.................... -- (27,461,801) (3,982,495)
Production...................... (2,832,000) (20,609,000) (24,574,881)
============ ============== ==============
End of year..................... 98,055,529 95,865,466 120,862,905
============ ============== ==============
Proved developed reserves at end of
year............................... 76,754,651 75,388,667 106,150,132
============ ============== ==============
Equity in proved reserves of equity
investee............................. 28,752,931
--------------
</TABLE>
F-19
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STANDARDIZED MEASURE -- The table of the Standardized Measure of Discounted
Future Net Cash Flows relating to the Company's ownership interests in proved
oil and gas reserves as of year end is shown below (in thousands):

AS OF DECEMBER 31,
----------------------------------
1994 1995 1996
---------- ---------- ----------
Future cash inflows.................. $ 170,237 $ 210,818 $ 422,377
Future oil and natural gas operating
expenses........................... (47,895) (43,204) (204,741)
Future development costs............. (40,622) (38,680) (31,208)
Future income tax expenses........... (852) (14,422) (37,156)
---------- ---------- ----------
Future net cash flows................ 80,868 114,512 149,272
10% annual discount for estimated
timing of cash flows............... (12,376) (15,513) (23,926)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows.............. $ 68,492 $ 98,999 $ 125,346
========== ========== ==========
Company's share of equity method
investee's standardized measure of
discounted future net cash flows... $ 29,078
----------

Future cash flows are computed by applying year end prices of oil and
natural gas to year end quantities of proved oil and natural gas reserves.
Future operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the Company's proved oil and natural gas reserves at
the end of the year, based on year end costs and assuming continuation of
existing economic conditions.

Future income taxes are based on year end statutory rates, adjusted for
operating loss carryforwards and tax credits. A discount factor of 10% was used
to reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and gas properties.

The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and natural 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.

F-20
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CHANGE IN STANDARDIZED MEASURE -- Changes in standardized measure of future
net cash flows relating to proved oil and gas reserves are summarized below (in
thousands):

1994 1995 1996
---------- ---------- ----------
Changes due to current year operations:
Sales of oil & gas, net of
production costs.............. $ (3,532) $ (26,200) $ (40,727)
Sales of reserves in place...... -- (20,027) (4,639)
Extensions & discoveries........ 4,977 18,595 7,941
Purchase of reserves in place... 54,134 21,143 12,601
Future development costs
incurred...................... 4,883 7,834 7,270
Changes due to revisions in
standardized variables
Price & production costs........ (8,793) 23,926 52,020
Revisions of previous quantity
estimates..................... (10,008) (950) (1,857)
Estimated future development
costs......................... (4,535) (8,825) (1,187)
Income taxes.................... 8,185 (11,613) (17,560)
Accretion of discount........... 1,211 6,181 10,393
Production rates (timing) and
other......................... 11,363 20,443 2,092
---------- ---------- ----------
Net increase......................... 57,885 30,507 26,347
Beginning of year.................... 10,607 68,492 98,999
---------- ---------- ----------
End of year.......................... $ 68,492 $ 98,999 $ 125,346
========== ========== ==========

Sales of oil and natural gas, net of oil and natural gas operating
expenses, are based on historical pre-tax results. Sales of oil and gas
properties, extensions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pre-tax
discounted basis.

F-21
<PAGE>
DOMAIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(NOTE 1)
(IN THOUSANDS, EXCEPT SHARE DATA)
(UNAUDITED)

SUCCESSOR
-------------------------
DECEMBER 31, MARCH 31,
1996 1997
------------ ---------
ASSETS
Cash and cash equivalents............ $ 36 $ 6,082
Restricted certificate of deposit.... 8,000 8,000
Accounts receivable.................. 19,456 13,989
IPF Program notes receivable, current
portion............................ 7,874 8,512
Prepaid and other current assets..... 1,525 1,468
------------ ---------
Total current assets............ 36,891 38,051
IPF Program notes receivable......... 13,836 19,018
Oil and natural gas properties, full
cost method........................ 66,176 66,752
Less: Accumulated depreciation,
depletion and amortization......... -- (3,116)
Investments and other assets......... 5,526 4,959
------------ ---------
Total assets.................... $122,429 $ 125,664
============ =========
LIABILITIES
Accounts payable..................... $ 14,018 $ 4,491
Accrued expenses..................... 42 2,880
Current maturities of long-term
debt............................... 24,900 23,500
------------ ---------
Total current liabilities....... 38,960 30,871
Long-term debt....................... 54,512 60,338
Deferred income taxes................ -- 1,550
------------ ---------
Total liabilities............... 93,472 92,759
Minority interest.................... 380 412

STOCKHOLDERS' EQUITY

Common stock:
$0.01 par value, 15,080,000 shares
authorized and 7,177,681 and
7,567,988 issued and outstanding
at December 31, 1996 and March 31,
1997, respectively............. 72 76
Additional paid-in capital........... 28,505 33,282
Notes receivable -- stockholders..... -- (546)
Retained earnings.................... -- (319)
------------ ---------
Total stockholders' equity...... 28,577 32,493
------------ ---------
Total liabilities and
stockholders' equity............ $122,429 $ 125,664
============ =========

The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-22
<PAGE>
DOMAIN ENERGY CORPORATION
COMBINED AND CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)
(UNAUDITED)

THREE MONTHS ENDED MARCH
31,
------------------------
PREDECESSOR SUCCESSOR
1996 1997
------------ ----------
REVENUES
Oil and natural gas.................. $ 15,688 $ 12,782
IPF Activities....................... 340 732
Other................................ 115 (292)
------------ ----------
Total revenues............. 16,143 13,222
------------ ----------
EXPENSES
Lease operating...................... 2,127 3,060
Production and severance taxes....... 279 413
Depreciation, depletion and
amortization....................... 7,613 3,282
General and administrative........... 1,089 792
Corporate overhead allocation........ 939 --
Stock compensation................... -- 3,150
------------ ----------
Total operating expenses... 12,047 10,697
Income from operations............... 4,096 2,525
Interest expense..................... -- 1,109
------------ ----------
Income before income taxes........... 4,096 1,416
Income tax provision................. 1,342 1,735
------------ ----------
Net income (loss).................... $ 2,754 $ (319)
============ ==========
Net income (loss) per share.......... $ (0.03)
Common Stock and common stock
equivalents outstanding............ 9,156

The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-23
<PAGE>
DOMAIN ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
ADDITIONAL NOTES TOTAL
COMMON PAID IN RECEIVABLE -- RETAINED STOCKHOLDERS'
STOCK CAPITAL STOCKHOLDERS EARNINGS EQUITY
------- ---------- ------------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996......... $ 72 $ 28,505 $-- $-- $28,577
Sale of common stock to employees.... 4 1,627 (546) -- 1,085
Stock compensation................... -- 3,150 -- -- 3,150
Net loss............................. -- -- -- (319) (319)
------- ---------- ------------- -------- -------------
Balance at March 31, 1997............ $ 76 $ 33,282 $ (546) $ (319) $32,493
======= ========== ============= ======== =============
</TABLE>
The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-24
<PAGE>
DOMAIN ENERGY CORPORATION
COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

THREE MONTHS ENDED
MARCH 31,
-----------------------
PREDECESSOR SUCCESSOR
1996 1997
----------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).................... $ 2,754 $ (319)
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization................... 7,613 3,282
Stock option compensation....... -- 3,150
Deferred income taxes........... 320 1,550
Minority interest............... -- 32
Changes in operating assets and liabilities:
Decrease (increase) in accounts
receivable..................... (6,302) 5,467
Decrease (increase) in prepaid
and other current assets....... (117) 57
Increase (decrease) in accounts
payable and accrued expenses... 1,447 (5,107)
----------- ---------
Net cash provided by operating
activities......................... 5,715 8,112
CASH FLOWS FROM INVESTING ACTIVITIES:
Investments in oil and natural gas
properties......................... (9,306) (3,858)
Proceeds from sale of oil and gas
properties......................... 412 1,700
IPF Program investments of capital
(notes receivable)................. (2,314) (9,246)
IPF Program return of capital (notes
receivable)........................ 517 3,426
Investment and other assets.......... 57 401
----------- ---------
Net cash used in investing
activities......................... (10,634) (7,577)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from debt borrowings........ -- 9,379
Repayments of debt borrowings........ -- (4,953)
Advances from Parent, net............ 5,285 --
Sale of common stock................. -- 1,085
----------- ---------
Net cash provided by financing
activities......................... 5,285 5,511
Increase in cash and cash
equivalents........................ 366 6,046
Cash and cash equivalents, beginning
of period.......................... 0 36
----------- ---------
Cash and cash equivalents, end of
period............................. $ 366 $ 6,082
=========== =========

The accompanying notes are an integral part of the combined and
consolidated financial statements.

F-25
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements included herein have been prepared by Domain
Energy Corporation (the "Company"), without audit pursuant to the rules and
regulations of the Securities and Exchange Commission, and reflect all
adjustments which are, in the opinion of management, necessary to present a fair
statement of the results for the interim periods on a basis consistent with the
annual audited financial statements. All such adjustments are of a normal
recurring nature. The results of operations for the interim periods are not
necessarily indicative of the results to be expected for an entire year. Certain
information, accounting policies and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been omitted pursuant to such rules and regulations, although
the Company believes that the disclosures are adequate to make the information
presented not misleading. These financial statements should be read in
conjunction with the Company's audited annual financial statements included
herein at pages F-2 through F-21.

2. STOCKHOLDERS' EQUITY

STOCK PURCHASE AND OPTION PLAN -- The Company recently adopted the Amended
and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain
Energy Corporation and Affiliates (the "Stock Purchase and Option Plan"). The
Stock Purchase and Option Plan authorizes the issuance of options to acquire up
to 867,091 shares of Common Stock and the Company has reserved 867,091 shares of
Common Stock for issuance in connection therewith. The Stock Purchase and Option
Plan will be administered by the Compensation Committee of the Board of
Directors. Pursuant to the Stock Purchase and Option Plan, the Company may grant
to employees, directors or other persons having a unique relationship with the
Company or its affiliates, singly or in combination, Incentive Stock Options,
Other Stock Options, Stock Appreciation Rights, Restricted Stock, Purchase
Stock, Dividend Equivalent Rights, Performance Units, Performance Shares or
Other Stock-Based Grants, in each case as such terms are defined therein. The
terms of any such grant will be determined by the Compensation Committee and set
forth in a separate grant agreement. The exercise price will be at least equal
to 100% of fair market value of the Common Stock on the date of grant in the
case of Incentive Stock Options and the exercise price of Other Stock Options
will be at least equal to 50% of fair market value of the Common Stock on the
date of grant, provided that options to purchase up to 433,546 shares of Common
Stock may be granted with an exercise price equal to $.01 per share, which is
the par value of the Common Stock. Non-Qualified Stock Options and Other Stock
Options may be exercisable for up to ten years.

On February 21, 1997 (the "Grant Date"), the Company granted to the
officers of the Company, pursuant to separate Non-Qualified Stock Option
Agreements (collectively, as amended, the "Stock Option Agreements") between the
Company and each of such persons, options to purchase a total of 753,998 shares
of Common Stock under the Stock Purchase and Option Plan. In addition, the
Company has granted options to purchase an aggregate of 95,696 shares of Common
Stock to other employees of the Company. Under the terms of the Stock Option
Agreements, 50% of the options granted to each such person are designated as
time options (collectively the "Time Options"), with an exercise price equal to
$4.18 per share, and 50% are designated as performance options (collectively,
the "Performance Options"), with an exercise price equal to $.01 per share. The
Time Options become exercisable as to 20% of the shares of Common Stock subject
thereto on the first anniversary of the Grant Date and are exercisable as to an
additional 20% of such shares upon each anniversary of the Grant Date
thereafter. The Performance Options become exercisable at any time following the
second anniversary of the Grant Date, when the Investment Return Hurdle (as such
term is defined) is met; provided that the Performance Options become
exercisable as to 100% of the shares of Common Stock subject thereto on the
ninth anniversary of the Grant Date.

F-26
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
aggregate of 390,307 shares of Common Stock at an average price of $4.18 per
share. To facilitate such purchases, the Company loaned the Management Investors
an aggregate of approximately $546,000. All such indebtedness of such person
accrues interest at the rate of 8% per annum, payable semiannually; provided
that each Management Investor may elect to satisfy his or her semiannual
interest payment obligation by increasing the principal amount of the
indebtedness owed to the Company by the amount of interest otherwise payable. As
security for such loans made by the Company, each Management Investor pledged to
the Company, and granted a first priority security interest in, the shares of
Common Stock purchased by such Management Investor pursuant to its respective
Management Investor Subscription Agreement and is required to pledge, and grant
a first priority security interest in, all other shares of Common Stock that
each such person may subsequently acquire, including, without limitation, upon
exercise of options to purchase shares of Common Stock. In addition, in April
1997, other employees of the Company purchased 95,696 shares of Common Stock at
an average price of $4.18 per share.

OPTION TO ACQUIRE COMMON STOCK -- Pursuant to the Subscription Agreement,
dated December 31, 1996 (the "First Reserve Subscription Agreement"), between
the Company and Fund VII, the Company granted to Fund VII an option (the "First
Reserve Option") to acquire 1,914,048 shares of Common Stock for an aggregate
purchase price of $8.0 million plus any cash interest payment on the Note
actually received by Fund VII (the "Option Price"). The Option Price may be paid
by Fund VII (i) prior to the date on which the Note has been paid in full, by
delivery to the Company of the Note together with the payment in cash of any
principal or interest payments on the Note previously received by Fund VII and
(ii) after the date on which the Note has been paid in full, by payment of the
Option Price in cash. In connection with the Offering, the Company and Fund VII
have agreed to restructure the terms of the First Reserve Option as set forth
below.

The Company and Fund VII have agreed that concurrently with consummation of
the Offering, Fund VII will purchase, at a price per share equal to the Price to
Public set forth on the cover page of this Prospectus, a number of shares of
Common Stock such that the aggregate purchase price paid by Fund VII for such
shares equals $8,681,000. The amount of $8,681,000 represents the sum of (i) the
outstanding principal balance of the note plus estimated accrued interest
thereon through June 15, 1997 and (ii) $500,000 in cash to be paid by Fund VII.

In accordance with APB 14, $1.0 million of the Note, representing the
estimated fair value of the First Reserve Option, has been reclassified from
notes payable to additional paid-in capital.

3. SALE OF NON-CORE ASSETS

On April 9, 1997, the Company sold its interest in a natural gas
development project located in northwest Michigan (the "Michigan Development
Project"). The Company received $2.1 million in cash and will receive an
additional $5.4 million from the payment of an interest-bearing note receivable.
The aggregate sale price approximated the Company's carrying value.

F-27
<PAGE>
INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Stockholders of
Domain Energy Corporation

We have audited the accompanying statement of revenues and direct operating
expenses of the properties acquired by Tenneco Ventures Corporation, predecessor
to Domain Energy Corporation, (the "Company") from Pennzoil Exploration and
Production Corporation and Pennzoil Petroleum Company (collectively "Pennzoil")
for the eleven month period ended November 30, 1994. This statement is the
responsibility of the Company's management. Our responsibility is to express an
opinion on the statement based on our audit.

We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the statement is free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statement. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall presentation of the statement. We believe that our audit
provides a reasonable basis for our opinion.

The accompanying statement was prepared for the purpose of complying with
certain rules and regulations of the Securities and Exchange Commission (for
inclusion in the Registration Statement on Form S-1 of Domain Energy
Corporation) and is not intended to be a complete financial presentation of
Pennzoil's interests in the properties described above.

In our opinion, the statement referred to above presents fairly, in all material
respects, the revenues and direct operating expenses of the properties acquired
by the Company from Pennzoil for the eleven month period ended November 30,
1994, in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Houston, Texas
June 13, 1997

F-28
<PAGE>
DOMAIN ENERGY CORPORATION
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION
FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION
AND PENNZOIL PETROLEUM COMPANY
FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994

(IN THOUSANDS)
--------------
Oil and gas revenues................. $ 23,047
Direct operating expenses............ 6,179
--------------
Revenues in excess of direct
operating expenses................. $ 16,868
==============

The accompanying notes are an integral part of this statement.

F-29
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION
FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION
AND PENNZOIL PETROLEUM COMPANY
FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994

1. OPERATIONS, ORGANIZATION AND BASIS OF PRESENTATION

The accompanying statement represents the interests in the natural gas and
oil revenues and direct operating expenses of the natural gas and oil producing
properties acquired by Tenneco Ventures Corporation, predecessor to Domain
Energy Corporation (the "Company") from Pennzoil Exploration and Production
Company and Pennzoil Petroleum Company (collectively "Pennzoil") on December 1,
1994 for approximately $51,300,000. The oil and gas producing properties
acquired are located primarily in the Gulf of Mexico. These properties are
referred to herein as the "Properties."

The accompanying statement was derived from the historical accounting
records of Pennzoil. Direct operating expenses include payroll, lease and well
repairs, maintenance and other direct operating expenses.

ACCRUAL BASIS STATEMENTS -- Memorandum adjustments have been made to the
financial information in order to present the accompanying statement in
accordance with generally accepted accounting principles.

REVENUE RECOGNITION AND GAS BALANCING -- The Company recognized oil and gas
revenue from its interests in producing wells as oil and gas was sold from those
wells. Accordingly, the Company used the sales method to account for gas
production volume imbalances. Under the sales method of accounting, revenue is
recorded based on the sales of production. Substantially all such gas imbalances
were anticipated to be settled with production in future periods. At November
30, 1994, the Company was entitled to additional future production from the
Properties of approximately 901,000 mcf.

USE OF ESTIMATES -- A number of estimates and assumptions have been made
relating to the preparation of this statement in conformity with generally
accepted accounting principles. Actual results could differ from those
estimates.

2. OMITTED HISTORICAL FINANCIAL INFORMATION

Historical financial statements reflecting financial position, results of
operations and cash flows required by generally accepted accounting principles
are not presented as such information is not readily available on an individual
property basis and not meaningful for the properties. Historically no allocation
of general and administrative, litigation, interest or federal income tax
expense was made to the Properties, and depreciation, depletion and amortization
was computed based on Pennzoil's basis in the Properties. Accordingly, the
statement is presented in lieu of the financial statements required under Rule
3-05 of Securities and Exchange Commission Regulation S-X.

3. COMMITMENT AND CONTINGENCIES

The Company is unaware of any legal, environmental or other contingencies
that would be materially important in relation to the statement.

4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

ESTIMATED NET QUANTITIES OF PROVED AND DEVELOPED OIL AND GAS RESERVES --
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 be
expected to be recovered through existing wells with existing equipment and
operating methods.

F-30
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION
FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION
AND PENNZOIL PETROLEUM COMPANY
FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994 -- (CONTINUED)

The following tables present the estimated net proved and proved developed
oil and gas reserves, attributable to the Properties at November 30, 1994, along
with a summary of changes in the quantities of net proved reserves during the
eleven months ended November 30, 1994.

NOVEMBER 30, 1994
----------------------------------
OIL, CONDENSATE
AND NATURAL
NATURAL GAS GAS LIQUIDS
(MCF) (BBLS)
------------ ----------------
Proved Reserves:
Beginning of period............. 59,970,693 1,481,458
Production...................... (10,722,190) (218,649)
------------ ----------------
End of period................... 49,248,503 1,262,809
============ ================
Proved Developed Reserves --
End of period................... 39,457,176 682,914
============ ================

STANDARDIZED MEASURE -- The Standardized Measure of Discounted Future Net
Cash Flows relating to the Company's ownership interest in proved oil and gas
reserves attributable to the Properties as of November 30, 1994 are shown below
(in thousands):

Future cash inflows.................. $ 96,693
Future oil and natural gas operating
expenses........................... (28,451)
Future development costs............. (21,245)
Future income tax expense............ (17,859)
----------
Future net cash flows................ 29,138
10% annual discount for estimated
timing of net cash flows........... (4,839)
----------
Standardized measure of discounted
future net cash flows.............. $ 24,299
==========

Future cash flows were computed by applying period end prices of oil and
natural gas to period end quantities of proved oil and natural gas reserves.
Future operating expenses and development costs were computed primarily by the
Company's petroleum engineers by estimating the amount and timing of the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves attributable to the Properties at the end of the
period, based on period end costs and assuming continuation of existing economic
conditions.

Future income taxes were based on period end statutory rates. A discount
factor of 10% was used to reflect the timing of future net cash flows. The
standardized measure of discounted future net cash flows is not intended to
represent the replacement cost or fair market value of the Properties.

The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the oil and
natural gas reserves attributable to the Properties. 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,
a discount factor more representative of the time value of money and the risks
inherent in reserve estimates.

F-31
<PAGE>
DOMAIN ENERGY CORPORATION
NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION
FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION
AND PENNZOIL PETROLEUM COMPANY
FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994 -- (CONTINUED)

CHANGES IN THE STANDARDIZED MEASURE -- Changes in the standardized measure
of discounted future net cash flows relating to proved reserves attributable to
the Properties for the eleven months ended November 30, 1994 are summarized
below (in thousands):

Standardized measure, beginning of
period............................. $ 40,363
Sales, net of production costs....... (16,868)
Net change in income taxes........... 6,410
Accretion of discount................ (5,606)
----------
Standardized measure, end of
period............................. $ 24,299
==========

F-32
<PAGE>
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206

APPRAISAL REPORT
AS OF
DECEMBER 31, 1996
ON
CERTAIN INTERESTS
OWNED BY
DOMAIN ENERGY VENTURES CORPORATION
AND
DOMAIN ENERGY PRODUCTION CORPORATION

PROVED RESERVES

FOREWARD

SCOPE OF INVESTIGATION

This report presents an appraisal, as of December 31, 1996, of the extent
and value of the proved crude oil, condensate, and natural gas reserves of
certain property interests owned by (i) Domain Energy Ventures Corporation
(Domain), (ii) the Matrix Limited Partnership owned by Domain, and (iii) Domain
Energy Production Corporation through the Investment Fund I (DEPC Fund I) and
the Investment Fund II (DEPC Fund II). DEPC Fund I is composed of four
investors, one of which is Domain Energy Corporation. Domain Energy Corporation
is the managing partner for DEPC Fund I and its ownership interest is 10 percent
of the total working interest owned by DEPC Fund I. The other investors
participate as net profits interest owners in the remaining 90 percent of the
total working interest taken by DEPC Fund I. The interests evaluated herein are
the total of Domain Energy Corporation's 10 percent and the 90 percent owned by
the other three Participants in DEPC Fund I. DEPC Fund II is composed of four
investors, one of which is Domain Energy Corporation. Domain Energy Corporation
is the managing partner for DEPC Fund II and its ownership interest is 30
percent of the total working interest owned by DEPC Fund II. The other investors
participate as net profits interest owners in the remaining 70 percent of the
total working interest taken by DEPC Fund II. The interest evaluated herein are
the total of Domain Energy Corporation's 30 percent and the 70 percent owned by
the other three participants in DEPC Fund II. Those properties consist of
certain productive leasehold interests located in Alabama, Louisiana,
Mississippi, and Texas and offshore from Alabama, Louisiana, and Texas.

This report estimates values for proved reserves using initial prices and
costs based on data provided by Domain with no increases in the future based on
inflation. A detailed explanation of the future price and cost assumptions is
included in the Valuation of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves.
Gross reserves are defined as the total estimated petroleum remaining to be
produced from these properties after December 31, 1996. Net reserves are defined
as that portion of the gross reserves attributable to the interests of Domain,
DEPC Fund I, or DEPC Fund II after deducting royalties and interests owned by
others.

Values of the net reserves in this report are expressed in terms of
estimated future gross revenue, future net revenue, and present worth. Future
gross revenue is that revenue which will accrue from the production and sale of
the estimated production taxes, operating expenditures, and capital costs from
the future gross revenue. Operating expenditures include field operating costs,
ad valorem taxes, and the estimated expenses of direct supervision but do not
include that portion of general administrative costs sometimes allocated to
production. Future income tax expenses were not taken into account in the
preparation of these estimates. Present worth is defined as future net revenue
discounted at a specified arbitrary discount rate compounded

A-1
<PAGE>
DEGOLYER AND MACNAUGHTON

monthly over the expected period of realization. This report shows present worth
values using a discount rate of 10 percent.

Estimates of oil, condensate, and gas reserves and future net revenue
should be regarded only as estimates that may change as further production
history and additional information become available. Not only are such reserves
and revenue estimates based on that information which is currently available,
but such estimates are also subject to the uncertainties inherent in the
application of judgmental factors in interpreting such information.

AUTHORITY

This report was prepared at the request of Mr. Douglas H. Woodul, Vice
President -- Production, Domain.

SOURCE OF INFORMATION

Information used in the preparation of this report was obtained from the
Domain files, from records on file with the appropriate regulatory agencies, and
from public sources. In the preparation of this report we have relied, without
independent verification, upon such information furnished by Domain with respect
to property interests, production from such properties, current costs of
operation and development, current prices for production, agreements relating to
current and future operations and sale of production, and various other
information and data that were accepted as represented. A field examination of
the properties was not considered necessary for the purposes of this report.

A-2
<PAGE>
DEGOLYER AND MACNAUGHTON

CLASSIFICATION OF RESERVES

Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs under
existing economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. In the
analyses of production-decline curves, reserves were estimated only to the limit
of economic rates of production under existing economic and operating conditions
using prices and costs as of the date the estimate is made, including
consideration of changes in existing prices provided only by contractual
arrangements but not including escalations based upon future conditions. The
petroleum reserves are classified as follows:

PROVED -- Reserves that have been proved to a high degree of certainty
by analysis of the producing history of a reservoir and/or by volumetric
analysis of adequate geological and engineering data. Commercial
productivity has been established by actual production, successful testing,
or in certain cases by favorable core analyses and electrical-log
interpretation when the producing characteristics of the formation are
known from nearby fields. Volumetrically, the structure, areal extent,
volume, and characteristics of the reservoir are well defined by a
reasonable interpretation of adequate subsurface well control and by known
continuity of hydrocarbon-saturated material above known fluid contacts, if
any, or above the lowest known structural occurrence of hydrocarbons.

DEVELOPED -- Reserves that are recoverable from existing wells with
current operating methods and expenses.

Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells producing
from present completion intervals with normal operating methods and
expenses. Developed nonproducing reserves are in reservoirs behind the
casing or at minor depths below the producing zone and are considered
proved by production from other wells in the field, by successful
drill-stem tests, or by core analyses from the particular zones.
Nonproducing reserves require only moderate expense to be brought into
production.

UNDEVELOPED -- Reserves that are recoverable from additional wells yet
to be drilled.

Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves requires
drilling of additional wells, major deepening of existing wells, or
installation of enhanced recovery or other facilities.

Reserves recovered by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending upon the
extent to which such enhanced recovery methods are in operation. These reserves
are considered to be proved only in cases where a successful fluid injection
program is in operation, a pilot program indicates successful fluid injection,
or information is available concerning the successful application of such
methods in the same reservoir and it is reasonably certain that the program will
be implemented.

A-3
<PAGE>
DEGOLYER AND MACNAUGHTON

ESTIMATION OF RESERVES

Estimates of reserves were prepared by the use of standard geological and
engineering methods generally accepted by the petroleum industry. The method or
combination of methods used in the analysis of each reservoir was tempered by
experience with similar reservoirs, stage of development, quality and
completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original
oil in place (OOIP) and original gas in place (OGIP). Structure maps were
prepared to delineate each reservoir, and isopach maps were constructed to
estimate reservoir volumes. Electrical logs, radioactivity logs, core analyses,
and other available data were used to prepare these maps as well as to calculate
representative values for porosity and water saturation. When adequate data were
available and when circumstances justified, material balance and other
engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery
factors to OOIP or OGIP. These recovery factors were based on consideration of
the type of energy inherent in the reservoirs, analyses of the petroleum, the
structural positions of the properties, and the production histories. When
applicable, material balance and other engineering methods were used to estimate
recovery factors. An analysis of reservoir performance, including production
rate, reservoir pressure, and gas-oil ratio behavior, was used in the
calculation of reserves.

For depletion-type reservoirs or those whose performance disclosed a
reliable decline in producing-rate trends or other diagnostic characteristics,
reserves were estimated by the application of appropriate decline curves or
other performance relationships. In the analyses of production-decline curves,
reserves were estimated only to the limits of economic production based on
current economic conditions.

In certain cases, when the previously named methods could not be used,
reserves were estimated by analogy with similar wells or reservoirs for which
more complete data were available.

Future oil and gas producing rates estimated for this report are based on
production rates considering the most recent data available or, in certain
cases, are based on estimates provided by Domain. The rates used for future
production are estimated to be within the capacity of a well or reservoir to
produce.

Data available from wells drilled on the appraised properties through
December 31, 1996, were used in estimating gross ultimate recovery. Gross
production estimated to December 31, 1996, when applicable, was deducted from
gross ultimate recovery to arrive at estimates of gross reserves. This required
that production rates be estimated for up to 5 months since production data were
available only through July 1996 in certain fields.

Gas reserves are expressed as salable reserves at a temperature of 60
degrees Fahrenheit (F) and at the legal pressure bases of the states or areas in
which the reserves are located. Condensate reserves estimated herein are those
to be obtained by normal separator recovery.

A-4
<PAGE>
DEGOLYER AND MACNAUGHTON

The proved reserves, as of December 31, 1996, of the properties appraised
are estimated as follows, expressed in barrels (bbl) and thousands of cubic feet
(Mcf):

<TABLE>
<CAPTION>
GROSS RESERVES NET RESERVES
---------------------------- -------------------------
OIL AND OIL AND
CONDENSATE GAS CONDENSATE GAS
(BBL) (MCF) (BBL) (MCF)
----------- -------------- ---------- ------------
DOMAIN
Proved
<S> <C> <C> <C> <C>
Developed............. 275,866,767 410,903,065 7,740,848 46,979,647
Undeveloped........... 268,052 40,304,512 46,463 9,744,742
----------- -------------- ---------- ------------
Total Proved............... 276,134,819 451,207,577 7,787,311 56,724,389

MATRIX LIMITED PARTNERSHIP
Proved
Developed............. 36,473 38,804,681 7,685 3,940,863
Undeveloped........... 3,333 2,564,000 178 137,217
----------- -------------- ---------- ------------
Total Proved............... 39,806 41,368,681 7,863 4,078,080

DEPC FUND I
Proved
Developed............. 359,641 86,955,018 49,983 14,317,813
Undeveloped........... 70,875 11,120,000 15,571 2,620,854
----------- -------------- ---------- ------------
Total Proved............... 430,516 98,075,018 65,554 16,938,667

DEPC FUND II
Proved
Developed............. 0 888,744 0 149,922
Undeveloped........... 0 0 0 0
----------- -------------- ---------- ------------
Total Proved............... 0 888,744 0 149,922
</TABLE>
A-5
<PAGE>
DEGOLYER AND MACNAUGHTON

VALUATION OF RESERVES

Revenue values in this report were estimated using the initial prices and
costs, as of December 31, 1996, provided by Domain. Future prices were estimated
using guidelines established by the Securities and Exchange Commission (SEC) and
the Financial Accounting Standards Board (FASB). The initial and future prices
and producing rates used in this report have been reviewed by Domain and it has
represented that the gas prices and rates used herein are those that Domain
could reasonably expect to receive.

In this report, values for proved reserves are based on projections of
estimated future production and revenue prepared for these properties. The
assumptions used for estimating future prices and costs are as follows:

DOMAIN

OIL AND CONDENSATE PRICES

Initial oil and condensate prices furnished by Domain range from $19.23 to
$24.71 per barrel and are held constant for the producing lives of the
properties.

NATURAL GAS PRICES

Initial gas prices, also furnished by Domain, range from $1.59 to $4.1403
per thousand cubic feet of gas and are held constant for the producing lives of
the properties.

MATRIX LIMITED PARTNERSHIP

OIL AND CONDENSATE PRICES

Initial oil and condensate prices furnished by Domain range from $20.98 to
$23.39 per barrel and are held constant for the producing lives of the
properties.

NATURAL GAS PRICES

Initial gas prices, also furnished by Domain, range from $2.50 to $3.9129
per thousand cubic feet of gas and are held constant for the producing lives of
the properties.

DEPC FUND I

OIL AND CONDENSATE PRICES

Initial oil and condensate prices furnished by Domain range from $22.85 to
$24.71 per barrel and are held constant for the producing lives of the
properties.

NATURAL GAS PRICES

Initial gas prices, also furnished by Domain, range from $1.641 to $4.0122
per thousand cubic feet of gas and are held constant for the producing lives of
the properties.

DEPC FUND II

OIL AND CONDENSATE PRICES

No oil or condensate reserves are assigned, therefore no price was
furnished.

NATURAL GAS PRICES

The initial gas price furnished by Domain is $1.641 per thousand cubic feet
of gas and are held constant for the producing life of the property.

A-6
<PAGE>
DEGOLYER AND MACNAUGHTON

For all properties, assumptions used for estimating operating and capital
costs are as follows:

OPERATING AND CAPITAL COSTS

Initial estimates of operating costs are based on data furnished by Domain
and are used for the lives of the properties with no increases in the future
based on inflation. Future capital expenditures are estimated using 1996 values
and are not adjusted for inflation.

The estimated future revenue to be derived from the production and sale of
the net proved reserves of the properties appraised herein under the economic
assumptions furnished by Domain is summarized as follows:

PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
($) ($) ($)
----------- ----------- --------------
DOMAIN
Future Gross Revenue.............340,203,048 37,704,437 377,907,485
Production Taxes................. 13,483,172 149,489 13,632,661
Operating Costs and Ad Valorem
Taxes..........................185,033,938 3,267,082 188,301,020
Capital Costs.................... 11,954,105 8,535,145 20,489,250
Future Net Revenue*..............129,731,833 25,752,721 155,484,554
Present Worth at 10 Percent*.....108,460,234 14,303,791 122,764,025
MATRIX LIMITED PARTNERSHIP
Future Gross Revenue............. 12,957,212 541,077 13,498,289
Production Taxes................. 0 0 0
Operating Costs and Ad Valorem
Taxes.......................... 1,758,862 93,600 1,852,462
Capital Costs.................... 910,967 97,500 1,008,467
Future Net Revenue*.............. 10,287,383 349,977 10,637,360
Present Worth at 10 Percent*..... 9,327,934 244,630 9,572,564
DEPC FUND I
Future Gross Revenue............. 53,972,978 9,809,858 63,782,836
Production Taxes................. 387,065 171,027 558,092
Operating Costs and Ad Valorem
Taxes.......................... 3,297,374 517,507 3,814,881
Capital Costs.................... 1,882,791 1,891,348 3,774,139
Future Net Revenue*.............. 48,405,748 7,229,976 55,635,724
Present Worth at 10 Percent*..... 36,128,387 5,484,908 41,613,295
DEPC FUND II
Future Gross Revenue............. 246,021 0 246,021
Production Taxes................. 18,452 0 18,452
Operating Costs and Ad Valorem
Taxes.......................... 38,940 0 38,940
Capital Costs.................... 0 0 0
Future Net Revenue*.............. 188,629 0 188,629
Present Worth at 10 Percent*..... 173,247 0 173,247

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

* Future income tax expenses were not taken into account in the preparation of
these estimates.

A-7
<PAGE>
DEGOLYER AND MACNAUGHTON

In our opinion, the information relating to estimated proved reserves,
estimated future net revenue from proved reserves, and present worth of
estimated future net revenue from proved reserves of oil, condensate, and gas
contained in this report has been prepared in accordance with Paragraphs 10-13,
15 and 30(a)-(b) of Statement of Financial Account Standards No. 69 (November
1982) of the FASB and Rules 4-10(a) (1)-(13) of Regulation S-X and Rule 302(b)
of Regulation S-K of the SEC; provided, however, (i) certain estimated data have
not been provided with respect to changes in reserves information and (ii)
future income tax expenses have not been taken into account in estimating the
future net revenue and present worth values set forth herein.

To the extent the above-enumerated rules regulations, and statements
require determinations of an accounting or legal nature or information beyond
the scope of our report, we are necessarily unable to express an opinion as to
whether the above-described information is in accordance therewith or sufficient
therefor.

A-8
<PAGE>
DEGOLYER AND MACNAUGHTON

SUMMARY AND CONCLUSIONS

Evaluated herein are certain interests owned by Domain, the Matrix Limited
Partnership, and Domain Energy Production Corporation through DEPC Fund I and
DEPC Fund II. The appraised properties are located in Alabama, Louisiana,
Mississippi, and Texas and offshore from Alabama, Louisiana, and Texas. The net
proved reserves, as of December 31, 1996, of the property interests owned by
Domain are estimated as follows, expressed in barrels (bbl) and thousands of
cubic feet (Mcf):

OIL AND
CONDENSATE GAS
(BBL) (MCF)
---------- ------------
Net Proved Reserves.................. 7,787,311 56,724,389

Revenue and costs attributable to the production and sale of Domain's net
proved reserves as of December 31, 1996, of the properties evaluated, under the
aforementioned assumptions concerning future prices and costs, are estimated as
follows:

PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
($) ($) ($)
-------------- ----------- --------------
DOMAIN
Future Gross Revenue............ 340,203,048 37,704,437 377,907,485
Production Taxes................ 13,483,172 149,489 13,632,661
Operating Costs and Ad Valorem
Taxes......................... 185,033,938 3,267,082 188,301,020
Capital Costs................... 11,954,105 8,535,145 20,489,250
Future Net Revenue*............. 129,731,833 25,752,721 155,484,554
Present Worth at 10 Percent*.... 108,460,234 14,303,791 122,764,025

* Future income tax expenses were not taken into account in the preparation of
these estimates.

The net proved reserves, as of December 31, 1996, of the properties owned
by the Matrix Limited Partnership are estimated as follows:

OIL AND
CONDENSATE GAS
(BBL) (MCF)
---------- -----------
Net Proved Reserves.................. 7,863 4,078,080

Revenue and costs attributable to the production and sale of Matrix Limited
Partnership's net proved reserves as of December 31, 1996, of the properties
evaluated, under the aforementioned assumptions concerning future prices and
costs, are estimated as follows:

PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
($) ($) ($)
------------ ----------- ------------
MATRIX LIMITED PARTNERSHIP
Future Gross Revenue............. 12,957,212 541,077 13,498,289
Production Taxes................. 0 0 0
Operating Costs and Ad Valorem
Taxes.......................... 1,758,862 93,600 1,852,462
Capital Costs.................... 910,967 97,500 1,008,467
Future Net Revenue*.............. 10,287,383 349,977 10,637,360
Present Worth at 10 Percent*..... 9,327,934 244,630 9,572,564

* Future income tax expenses were not taken into account in the preparation of
these estimates.

A-9
<PAGE>
DEGOLYER AND MACNAUGHTON

The net proved reserves, as of December 31, 1996, of the properties owned
by Domain Energy Production Corporation through DEPC Fund I are estimated as
follows:

OIL AND
CONDENSATE GAS
(BBL) (MCF)
---------- ------------
Net Proved Reserves.................. 65,554 16,938,667

Revenue and costs attributable to the production and sale of the net proved
reserves, as of December 31, 1996, of the DEPC Fund I properties, under the
aforementioned assumptions concerning future prices and costs, are estimated as
follows:

PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
($) ($) ($)
------------ ----------- ------------
DEPC FUND I
Future Gross Revenue.............. 53,972,978 9,809,858 63,782,836
Production Taxes.................. 387,065 171,027 558,092
Operating Costs and Ad Valorem
Taxes........................... 3,297,374 517,507 3,814,881
Capital Costs..................... 1,882,791 1,891,348 3,774,139
Future Net Revenue*............... 48,405,748 7,229,976 55,635,724
Present Worth at 10 Percent*...... 36,128,387 5,484,908 41,613,295

* Future income tax expenses were not taken into account in the preparation of
these estimates.

The net proved reserves, as of December 31, 1996, of the properties owned
by Domain Energy Production Corporation through DEPC Fund II are estimated as
follows:

OIL AND
CONDENSATE GAS
(BBL) (MCF)
---------- ---------
Net Proved Reserves.................. 0 149,922

Revenue and costs attributable to the production and sale of the net proved
reserves, as of December 31, 1996, of the DEPC Fund II properties, under the
aforementioned assumptions concerning future prices and costs, are estimated as
follows:

PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
($) ($) ($)
--------- ----------- ---------
DEPC FUND II
Future Gross Revenue............... 246,021 0 246,021
Production Taxes................... 18,452 0 18,452
Operating Costs and Ad Valorem
Taxes............................ 38,940 0 38,940
Capital Costs...................... 0 0 0
Future Net Revenue*................ 188,629 0 188,629
Present Worth at 10 Percent*....... 173,247 0 173,247

* Future income tax expenses were not taken into account in the preparation of
these estimates.

A-10
<PAGE>
DEGOLYER AND MACNAUGHTON

Gas reserves estimated herein are expressed at a temperature base of 60F
and at the legal pressure bases of the states or areas in which the reserves are
located.

Submitted,

/s/DEGOLYER AND MACNAUGHTON
DeGOLYER and MacNAUGHTON

SIGNED: March 26, 1997 /s/JAMES W. HAIL, JR., P.E.
James W. Hail, Jr., P.E.
Senior Vice President
DeGolyer and MacNaughton

A-11
<PAGE>
March 26, 1997

Mr. Herb A. Newhouse
Domain Energy Corporation
1100 Louisiana, Suite 1500
Houston, Texas 77002

Dear Mr. Newhouse:

In accordance with your request, we have estimated the proved reserves
and future revenue, as of December 31, 1996, to the Domain Energy Ventures
Corporation (Domain) interest and the Domain Energy Production Corporation Fund
II (DEPC Fund) interest in certain oil and gas properties located in the West
Delta 30 Field Area, federal waters offshore Louisiana. This letter summarizes
the results of our reports dated February 24, 1997, and February 26, 1997. This
report has been prepared using constant prices and costs and conforms to the
guidelines of the Securities and Exchange Commission (SEC).

We estimate the net reserves and future net revenue to the Domain
interest, as of December 31, 1996, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
------------------------------ ----------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ---------------------- ------------- ------------ --------------- ---------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 92,463 129,699 $ 3,600 $ 103,100
Non-Producing 167,675 892,194 3,778,900 3,179,700
Proved Undeveloped 108,610 876,744 4,408,600 3,315,500
------------- ------------ --------------- ---------------
Total Proved 368,748 1,898,637 $ 8,191,100 $ 6,598,300
</TABLE>
We estimate the net reserves and future net revenue to the DEPC Fund
interest, as of December 31, 1996, to be:
<TABLE>
<CAPTION>
Net Reserves Future Net Revenue
------------------------------ ----------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ---------------------- ------------- ------------ --------------- ---------------
<S> <C> <C> <C> <C>
Proved Developed
Producing 554,797 778,206 $ 6,000 $ 610,400
Non-Producing 1,006,060 5,353,157 22,593,100 19,019,700
Proved Undeveloped 651,665 5,260,459 26,365,500 19,825,300
------------- ------------ --------------- ---------------
Total Proved 2,212,522 11,391,822 $48,964,600 $39,455,400
</TABLE>
The oil reserves shown include crude oil and condensate. 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.

A-12
<PAGE>
The estimated reserves and future revenue shown are for proved developed
producing, proved developed non-producing, and proved undeveloped reserves. In
accordance with SEC guidelines, our estimates do not include any value for
probable or possible reserves which may exist for these properties. Our
estimates do not include any value which could be attributed to interests in
undeveloped acreage beyond those tracts for which undeveloped reserves have been
estimated.

Future gross revenue is Domain and DEPC Fund's share of the gross
(8/8ths) revenue from the properties. Future net revenue is after deducting
future capital costs, operating expenses, any applicable payments to net profits
interests, and abandonment costs, but before consideration of federal income
taxes. In accordance with SEC guidelines, the future net revenue has been
discounted at an annual rate of 10 percent to determine its "present worth." The
present worth is shown to indicate the effect of time on the value of money and
should not be construed as being the fair market value of the properties.

For the purposes of this report, a field inspection of the properties
has not been performed nor has the mechanical operation or condition of the
wells and their related facilities been examined. We have not investigated
possible environmental liability related to the properties; therefore, our
estimates do not include any costs which may be incurred due to such possible
liability. Also, our estimates do not include any salvage value for the lease
and well equipment, but do include our estimates of the costs to abandon the
wells, platforms, and production facilities. Abandonment costs are included with
other capital investments.

The oil and gas prices used in this report are the actual prices
received on December 31, 1996. Oil and gas prices are held constant in
accordance with SEC guidelines.

Lease and well operating costs are based on operating expense records of
Domain Energy Corporation. 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 Domain Energy Corporation 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.

We have made no investigation of potential gas volume and value
imbalances which may have resulted from overdelivery or underdelivery to the
Domain or the DEPC Fund interests. Therefore, our estimates of reserves and
future revenue do not include adjustments for the settlement of any such
imbalances; our projections are based on Domain and the DEPC Fund receiving
their net revenue interest share of estimated future gross gas production.

A-13
<PAGE>
The reserves included in this report are estimates only and should not
be construed as exact quantities. They may or may not be recovered; if
recovered, the revenues therefrom and the costs related thereto could be more or
less than the estimated amounts. A substantial portion of these reserves are for
behind pipe zones and undeveloped locations. Therefore, these reserves are based
on estimates of reservoir volumes and recovery efficiencies along with analogies
to similar production. As such reserve estimates are usually subject to greater
revision than those based on substantial production and pressure data, it may be
necessary to revise these estimates up or down in the future as additional
performance data become available. The sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may vary from
assumptions included in this report due to governmental policies and
uncertainties of supply and demand. Also, estimates of reserves may increase or
decrease as a result of future operations.

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

The titles to the properties have not been examined by Netherland,
Sewell & Associates, Inc., nor has the actual degree or type of interest owned
been independently confirmed. The data used in our estimates were obtained from
Domain Energy Ventures Corporation, Domain Energy Corporation, other interest
owners, various operators of the properties, and the nonconfidential files of
Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are
independent petroleum engineers, geologists, and geophysicists; we do not own an
interest in these properties and are not employed on a contingent basis. Basic
geologic and field performance data together with our engineering work sheets
are maintained on file in our office.

Very truly yours,

/s/ CLARENCE NETHERLAND
A-14
<PAGE>
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NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES
NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE
SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE
ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT
TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE
COMPANY SINCE SUCH DATE.

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TABLE OF CONTENTS

PAGE
----
Prospectus Summary...................... 3
Risk Factors............................ 11
Use of Proceeds......................... 19
Dividend Policy......................... 19
Capitalization.......................... 20
Dilution................................ 21
Unaudited Condensed Pro Forma Financial
Statements............................ 22
Selected Historical Financial Data...... 31
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................ 32
Business and Properties................. 43
Management.............................. 64
Transactions with Management and First
Reserve............................... 71
Security Ownership of Certain Beneficial
Owners and Management................. 73
Description of Capital Stock............ 74
Shares Eligible for Future Sale......... 75
Underwriting............................ 77
Notice to Canadian Residents............ 79
Legal Matters........................... 80
Experts................................. 80
Available Information................... 80
Glossary................................ 81
Index to Financial Statements........... F-1
Reports of Independent Petroleum
Engineers............................. A-1

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UNTIL JULY 19, 1997, ALL DEALERS EFFECTING TRANSACTIONS IN THE REGISTERED
SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED
TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO
DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR
UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.

[LOGO]

DOMAIN ENERGY
CORPORATION

6,000,000 Shares

Common Stock
($.01 par value)

PROSPECTUS

CREDIT SUISSE FIRST BOSTON
PAINEWEBBER INCORPORATED
PRUDENTIAL SECURITIES INCORPORATED
MORGAN KEEGAN & COMPANY, INC.

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