WESTPORT RESOURCES CORP, S-1, 2000-06-29

WESTPORT RESOURCES CORP
S-1, 2000-06-29

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JUNE 29, 2000
REGISTRATION NO. 333-
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--------------------------------------------------------------------------------
Securities and Exchange Commission
Washington, D.C. 20549
------------------
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
------------------
WESTPORT RESOURCES CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

<TABLE>
<S> <C> <C>
DELAWARE 1311 23-3020832
(State or Other Jurisdiction of (Primary standard industrial (I.R.S. Employer
Incorporation or Organization) classification code number) Identification Number)
</TABLE>
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410 SEVENTEENTH STREET, SUITE 2300
DENVER, COLORADO 80202
TELEPHONE: (303) 573-5404
(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant's Principal Executive Offices)

DONALD D. WOLF
CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE OFFICER
WESTPORT RESOURCES CORPORATION
410 SEVENTEENTH STREET, SUITE 2300
DENVER, COLORADO 80202
TELEPHONE: (303) 573-5404
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent for Service)
------------------
With a copy to:

<TABLE>
<S> <C>
MICHAEL E. DILLARD, P.C. WILLIAM J. WHELAN, III
AKIN, GUMP, STRAUSS, HAUER & FELD, L.L.P. CRAVATH, SWAINE & MOORE
1700 PACIFIC AVENUE, SUITE 4100 WORLDWIDE PLAZA, 825 EIGHTH AVENUE
DALLAS, TEXAS 75201 NEW YORK, NEW YORK 10019
TELEPHONE: (214) 969-2800 TELEPHONE: (212) 474-1000
FACSIMILE: (214) 969-4343 FACSIMILE: (212) 474-3700
</TABLE>

Approximate date of commencement of proposed sale to the public: As soon as
practicable on or after the effective date of this Registration Statement.

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

If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ] ___________________

If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ] _____________________

If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ] _____________________

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ] _____________________

CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------
TITLE OF EACH CLASS OF SECURITIES PROPOSED MAXIMUM AGGREGATE AMOUNT OF
TO BE REGISTERED OFFERING PRICE(1) REGISTRATION FEE(2)
------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock, par value $.01 per share.... $100,000,000 $26,400
------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Estimated solely for the purpose of calculating the amount of the
registration fee in accordance with Rule 457(o).
(2) Calculated pursuant to Rule 475(a) under the Securities Act based on an
estimate of the proposed maximum offering price.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT
SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION,
ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.
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--------------------------------------------------------------------------------
<PAGE> 2

The information in this prospectus is not complete and may be changed. We
may not sell these securities until the registration statement filed with
the Securities and Exchange Commission is effective. This prospectus is
not an offer to sell these securities and it is not soliciting an offer to
buy these securities in any state where the offer or sale is not
permitted.

SUBJECT TO COMPLETION, DATED JUNE 29, 2000

[WESTPORT LOGO]

WESTPORT RESOURCES CORPORATION

Common Stock

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

Prior to this offering, there has been no public market for our common
stock. The initial public offering price of the common stock is expected to be
between $ and $ per share. We intend to apply for the listing of our
common stock on The New York Stock Exchange under the symbol "WRC."

We are selling shares of common stock and the selling
stockholders are selling shares of common stock. We will not receive
any proceeds from the sale of shares by the selling stockholders.

The underwriters have an option to purchase from the selling stockholders a
maximum of additional shares to cover over-allotments of shares.

INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 8.

<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO
PRICE TO DISCOUNTS AND PROCEEDS TO SELLING
PUBLIC COMMISSIONS WESTPORT STOCKHOLDERS
-------- ------------- ----------- ------------
<S> <C> <C> <C> <C>
Per Share............................................ $ $ $ $
Total................................................ $ $ $ $
</TABLE>

Delivery of the shares of common stock will be made on or about
, 2000.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.

CREDIT SUISSE FIRST BOSTON
DONALDSON, LUFKIN & JENRETTE
LEHMAN BROTHERS
BANC OF AMERICA SECURITIES LLC
PETRIE PARKMAN & CO.

The date of this prospectus is , 2000.
<PAGE> 3

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUMMARY...................... 1
RISK FACTORS............................ 8
SPECIAL NOTE REGARDING FORWARD-LOOKING
STATEMENTS............................ 17
USE OF PROCEEDS......................... 18
DIVIDEND POLICY......................... 18
DILUTION................................ 19
CAPITALIZATION.......................... 20
SELECTED CONSOLIDATED FINANCIAL DATA.... 21
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
OF WESTPORT RESOURCES CORPORATION..... 23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS............................ 28
BUSINESS AND PROPERTIES................. 36
MANAGEMENT.............................. 51
CERTAIN TRANSACTIONS.................... 59
</TABLE>

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PRINCIPAL AND SELLING STOCKHOLDERS...... 60
DESCRIPTION OF CAPITAL STOCK............ 62
SHARES ELIGIBLE FOR FUTURE SALE......... 64
UNITED STATES TAX CONSEQUENCES TO
NON-U.S. HOLDERS...................... 65
UNDERWRITING............................ 68
NOTICE TO CANADIAN RESIDENTS............ 72
LEGAL MATTERS........................... 73
EXPERTS................................. 73
INDEPENDENT PETROLEUM ENGINEERS......... 73
WHERE YOU CAN FIND MORE INFORMATION..... 73
GLOSSARY OF OIL AND NATURAL GAS TERMS... 74
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS............................ F-1
REPORT OF INDEPENDENT PETROLEUM
ENGINEERS............................. A-1
</TABLE>

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

YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS DOCUMENT OR TO
WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
INFORMATION THAT IS DIFFERENT. THIS DOCUMENT MAY ONLY BE USED WHERE IT IS LEGAL
TO SELL THESE SECURITIES. THE INFORMATION IN THIS PROSPECTUS MAY ONLY BE
ACCURATE ON THE DATE OF THIS DOCUMENT.

DEALER PROSPECTUS DELIVERY OBLIGATION

UNTIL , 2000 (25 DAYS AFTER THE COMMENCEMENT OF THE OFFERING),
ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES, WHETHER OR NOT
PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS
IN ADDITION TO THE DEALER'S OBLIGATION TO DELIVER A PROSPECTUS WHEN ACTING AS AN
UNDERWRITER AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
i
<PAGE> 4

PROSPECTUS SUMMARY

This summary highlights selected information from this prospectus, but does
not contain all information that may be important to you. We encourage you to
read this prospectus in its entirety before making an investment decision.
References to "Westport," "we," "our" or "us" refer to Westport Resources
Corporation. Westport was formed in connection with the merger of Westport Oil
and Gas Company, Inc. with Equitable Production (Gulf) Company, an indirect,
wholly-owned subsidiary of Equitable Resources, Inc. that held certain Gulf of
Mexico assets. Unless expressly noted otherwise, the operating results and
property descriptions presented here are those of Westport Oil and Gas Company,
Inc., as adjusted to reflect the pro forma effect of its merger with Equitable
Production (Gulf) Company. Westport Oil and Gas Company, Inc. is referred to in
this document as "Westport Oil and Gas" and Equitable Production (Gulf) Company
is referred to in this document as "EPGC." Unless otherwise indicated, this
prospectus assumes that the underwriters' over-allotment option is not
exercised. We have provided definitions for some of the oil and natural gas
industry terms used in this prospectus in the "Glossary of Oil and Natural Gas
Terms" beginning on page 74.

ABOUT WESTPORT

Westport is an independent energy company engaged in oil and natural gas
exploitation, acquisition and exploration activities primarily in the United
States. We conduct operations in the Gulf of Mexico, the Rocky Mountains, West
Texas/Mid-Continent and the Gulf Coast. We focus on maintaining a balanced
portfolio of lower-risk, long-life onshore reserves and higher-margin offshore
reserves to provide a diversified cash flow foundation for our exploitation,
acquisition and exploration activities.

We have grown our reserves and production over the last three years at
compounded annual growth rates of 23% and 29%, respectively. Onshore, we have
built a strong asset base and achieved steady growth through both property
acquisitions and exploitation activities. We expect to further develop these
properties through lower-risk waterflooding and infill and horizontal drilling.
In the Gulf of Mexico, we own interests in 65 developed blocks and 67
undeveloped blocks, within which we have realized several recent discoveries and
have assembled a large number of future drilling opportunities. We have budgeted
$110 million in capital expenditures for 2000 to pursue our exploitation and
exploration opportunities. We believe that our exploitation and acquisition
expertise and our sizable exploration inventory, together with our operating
experience and efficient cost structure, provide us with substantial growth
potential.

As of December 31, 1999, we had proved reserves of 454.5 Bcfe, with a
present value of $544.4 million based on NYMEX prices of $25.60 per barrel of
oil and $2.30 per Mmbtu of natural gas. These reserves, of which 51% were
natural gas and 81% were classified as proved developed, had a reserve life
index of 7.5 years. We operate over 77% of our PV10 value, allowing us to better
manage expenses, capital allocation and the decision-making processes related to
other aspects of exploitation and exploration activities. We produced 60.8 Bcfe
in 1999 and 14.8 Bcfe in the first quarter of 2000. The following table sets
forth the volume and present value of our proved reserves at year-end 1999 and a
summary of our first quarter 2000 production by area:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999 FIRST QUARTER 2000
----------------------------------------- ----------------------------
PROVED % OF AVERAGE
RESERVES PRESENT VALUE PRESENT PRODUCTION % OF
AREA (BCFE) (IN MILLIONS) VALUE (MMCFE/D) PRODUCTION
---- ----------- -------------- ---------- ------------- ------------
<S> <C> <C> <C> <C> <C>
Gulf of Mexico................... 166.1 $228.6 42% 82.5 51%
Rocky Mountains.................. 186.7 210.2 38 54.1 33
West Texas/Mid-Continent......... 51.0 63.5 12 12.4 8
Gulf Coast....................... 50.7 42.1 8 13.7 8
----- ------ --- ----- ---
Total.................. 454.5 $544.4 100% 162.7 100%
===== ====== === ===== ===
</TABLE>

1
<PAGE> 5

OUR STRATEGY

Our strategy is to continue to grow our reserve base, diversify our risk
profile and expand our investment opportunities by executing on lower-risk
exploitation projects and acquisitions (65% to 75% of our capital budget), as
well as drilling higher-impact exploration prospects (25% to 35% of our capital
budget), thereby balancing risks while maintaining significant potential for
growth. To accomplish this we will:

- enhance our existing and acquired properties through exploitation to
enlarge our reserve base;

- pursue acquisitions with developmental upside to grow our inventory of
exploitation projects and to employ our operating expertise; and

- generate and drill an extensive prospect inventory in the Gulf of Mexico
by applying the latest available technology and leveraging off our
significant operational capabilities in that area.

We intend to implement our strategy as follows:

CONTINUE AN ACTIVE EXPLOITATION PROGRAM. In 1999, we drilled 79 development
wells onshore and nine development wells in the Gulf of Mexico. Additionally, we
enhanced two onshore waterfloods by drilling six injector wells and converting
four producing wells to injectors. We have identified prospective exploitation
projects both onshore and offshore with aggregate potential net unrisked
reserves of more than 300 Bcfe. In the Gulf of Mexico, we have recently made
discoveries on 10 blocks. We have commenced production on several of these
discoveries and are in the process of installing production facilities and
pursuing additional exploitation opportunities on these blocks. In addition,
during 2000, we intend to continue exploitation in the West Cameron 180/198
complex and the South Marsh Island 39 field. Onshore, we plan to drill more than
100 development wells in 2000. As of May 31, 2000, 56 of these wells had been
drilled and 52 were successful.

We acquired the West Cameron 180/198 complex, our most active offshore
area, in 1997, and have increased production from approximately 30 Mmcfe/d at
the date of acquisition to approximately 50 Mmcfe/d for the quarter ended March
31, 2000. In our most active onshore areas, Gooseberry, South Fryburg Tyler and
Bonepile, we have increased production through exploitation from approximately
13 Mmcfe/d for the quarter ended March 31, 1997 to approximately 24 Mmcfe/d for
the quarter ended March 31, 2000.

PURSUE AND CAPITALIZE ON ACQUISITIONS. Through a series of acquisitions
from 1995 to 1999, Westport Oil and Gas substantially increased its reserve base
by investing approximately $250 million in acquiring oil and natural gas
properties at an average cost of $0.90 per Mcfe. It invested an additional $53
million to exploit these acquired properties and added reserves at an average
cost of $0.47 per Mcfe, thereby reducing average acquisition costs by over 14%
to $0.77 per Mcfe. This has resulted in reserve additions that have fully
replaced our production from the acquired properties, while generating cash
flows to date sufficient to recoup more than 47% of total exploitation and
acquisition capital invested.

We believe that, due to a trend toward industry consolidation and asset
rationalization, we will continue to have opportunities to acquire oil and
natural gas properties at attractive rates of return. We have an experienced
team dedicated to executing our disciplined approach to identifying and
capturing these opportunities.

CAPITALIZE ON EXTENSIVE EXPLORATION OPPORTUNITIES. As of May 31, 2000, we
had a 67-block exploration inventory in the Gulf of Mexico, in addition to 65
developed blocks, several of which contain additional exploration opportunities.
We have under license 3-D seismic data covering over 10,000 square miles (1,460
blocks) and 2-D seismic data covering over 150,000 miles in this area. Our
strategy includes acquiring large working interests in internally generated
prospects in order to control activity, and then, prior to drilling, trading a
portion of our positions for prospects developed by others. This allows us to
achieve multiple prospect exposure while diversifying investment risk.

2
<PAGE> 6

Onshore, we hold interests in approximately 215,000 gross (approximately
100,000 net) undeveloped acres. Our onshore exploration effort is designed to
enhance reserve and production growth in our core areas by emphasizing and
applying the latest geological, geophysical and drilling technologies. We seek
exploration plays with geological and geophysical characteristics similar to
producing properties in our core areas in order to leverage our technical and
operational expertise. Recent onshore exploration activities have included
horizontal drilling in North Dakota and coalbed methane drilling in the Powder
River Basin of Wyoming.

MAINTAIN EFFICIENT OPERATIONS WITH A LOW COST STRUCTURE. We emphasize a low
overhead and operating expense structure and have historically reduced these
costs on a per-unit basis. From 1997 to 1999, Westport Oil and Gas reduced lease
operating expense from $0.82 per Mcfe to $0.69 per Mcfe and general and
administrative costs from $0.22 per Mcfe to $0.16 per Mcfe. Giving pro forma
effect to the transaction between Westport Oil and Gas and EPGC, lease operating
expense and general and administrative costs for the quarter ended March 31,
2000 were further reduced to $0.53 per Mcfe and $0.13 per Mcfe, respectively. We
believe that our focus on a low cost structure positions us to remain
competitive in our exploitation, acquisition and exploration activities.

OUR EXECUTIVE OFFICES

Our headquarters are located at 410 Seventeenth Street, Suite 2300, Denver,
Colorado 80202, and our telephone number is (303) 573-5404.

THE OFFERING

Common stock offered by
Westport....................... shares

Common stock offered by the
selling stockholders........... shares

Common stock to be outstanding
after this offering(1)......... shares

Use of proceeds.................. We intend to use the net proceeds from the
offering for repayment of a portion of the
debt under our credit agreement. We will
use the increased borrowing capacity under
the credit agreement, along with cash flow
from operations, to pursue exploitation,
acquisition and exploration activities and
for general corporate purposes.

Proposed New York Stock Exchange
symbol......................... "WRC"
---------------

(1) Excludes shares of common stock reserved for issuance under our
stock option plan of, which have been granted.

3
<PAGE> 7

SUMMARY CONSOLIDATED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table presents summary consolidated historical financial data
for the years ended December 31, 1997, 1998 and 1999 and for the three months
ended March 31, 1999 and 2000, in each case derived from the consolidated
financial statements of Westport Oil and Gas, and pro forma information prepared
as if the transaction between Westport Oil and Gas and EPGC had taken place on
March 31, 2000 with respect to the balance sheet data and as of January 1, 1999
with respect to the statement of operations data. The pro forma as adjusted
balance sheet data gives further effect to:

- the sale by us of shares of common stock in this offering at an
assumed initial public offering price of $ per share, after deducting
underwriting discounts and estimated offering expenses; and

- the application by us of the proceeds of that sale to repay a portion of
the debt under our credit agreement.

You should read the following data along with "Selected Consolidated
Financial Data," "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the consolidated financial statements and the
related notes, each of which is included in this prospectus. You should read the
pro forma information together with the unaudited pro forma combined financial
statements and related notes included in this prospectus.

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
------------------------------------------------------ ------------------------------
THREE MONTHS
ENDED THREE MONTHS
YEAR ENDED DECEMBER 31, MARCH 31, YEAR ENDED ENDED
-------------------------------- ------------------- DECEMBER 31, MARCH 31,
1997 1998 1999 1999 2000 1999 2000
--------- --------- -------- ------- --------- ------------ ---------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Revenues.................... $ 63,089 $ 51,505 $ 73,763 $14,978 $ 24,985 $138,635 $ 43,917
Operating costs and
expenses:
Lease operating expense... 19,583 21,554 22,916 5,620 6,623 30,131 7,838
Production taxes.......... 5,923 3,888 5,742 798 2,268 5,742 2,268
Exploration............... 7,424 14,664 7,314 1,038 1,871 7,314 1,871
Depletion, depreciation
and amortization........ 23,659 36,264 25,210 8,489 6,172 58,298 16,298
Impairment of proved
properties.............. 5,765 8,794 3,072 -- -- 3,072 235
Impairment of unproved
properties.............. 380 1,898 2,273 -- 235 2,273 --
General and
administrative.......... 5,316 5,913 5,297 1,580 4,547(1) 8,104 5,249(1)
--------- --------- -------- ------- --------- -------- --------
Total operating
expenses......... 68,050 92,975 71,824 17,525 21,716 114,934 33,759
--------- --------- -------- ------- --------- -------- --------
Operating income
(loss)........... (4,961) (41,470) 1,939 (2,547) 3,269 23,701 10,158
Other income (expense):
Interest expense.......... (5,635) (8,323) (9,207) (2,497) (2,047) (13,301) (3,070)
Interest income........... 309 403 489 99 193 489 193
Gain (loss) on sale of
assets -- net........... (13) -- 3,637 4,770 (17) 3,637 (17)
Other..................... (54) 29 16 16 (1) 16 (1)
--------- --------- -------- ------- --------- -------- --------
Income (loss) before income
taxes..................... (10,354) (49,361) (3,126) (159) 1,397 14,542 7,263
Benefit (provision) for
income taxes.............. 973 -- -- -- -- (5,090) (2,542)
--------- --------- -------- ------- --------- -------- --------
Net income (loss)........... $ (9,381) $ (49,361) $ (3,126) $ (159) $ 1,397 $ 9,452 $ 4,721
========= ========= ======== ======= ========= ======== ========
Weighted average number of
common shares outstanding:
Basic..................... 6,217 7,336 9,818 9,054 10,420 19,976 20,578
========= ========= ======== ======= ========= ======== ========
Diluted................... 6,217 7,336 9,818 9,054 10,616 20,067 20,774
========= ========= ======== ======= ========= ======== ========
Net income (loss) per common
share:
Basic..................... $ (1.51) $ (6.73) $ (0.32) $ (0.02) $ 0.13 $ 0.47 $ 0.23
========= ========= ======== ======= ========= ======== ========
Diluted................... $ (1.51) $ (6.73) $ (0.32) $ (0.02) $ 0.13 $ 0.47 $ 0.23
========= ========= ======== ======= ========= ======== ========
</TABLE>

4
<PAGE> 8

<TABLE>
<CAPTION>
AS OF MARCH 31, 2000
----------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Cash........................................................ $ 12,238 $ 19,836 $
Working capital............................................. 9,557 22,715
Total assets................................................ 269,503 502,933
Total long-term debt........................................ 105,462 155,462
Total debt.................................................. 106,462 156,462
Stockholders' equity........................................ 141,408 309,659
</TABLE>

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

(1) Includes compensation expense of $3.4 million recorded as a result of a
repurchase of employee stock options in March 2000 in connection with the
transaction between Westport Oil and Gas and EPGC.

(2) Adjusted EBITDA is presented because of its wide acceptance as a financial
indicator. Adjusted EBITDA (as used herein) is defined as net income (loss)
before interest expense, income taxes, depletion, depreciation and
amortization, impairment of unproved properties, impairment of proved
properties and exploration expense. Adjusted EBITDA should not be considered
as an alternative to net income (loss) or operating income (loss), as
defined by generally accepted accounting principles, as an indicator of a
company's financial performance or to cash flow as a measure of liquidity.

5
<PAGE> 9

SUMMARY OPERATING AND RESERVE DATA

The following estimates of net proved oil and natural gas reserves are
based on reports prepared by Ryder Scott Company L.P. and Netherland, Sewell &
Associates, Inc., independent petroleum engineers. A summary of Ryder Scott's
and Netherland, Sewell's reports on our proved reserves as of January 1, 2000 is
attached to this prospectus as Annex A. You should refer to "Risk Factors,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Business and Properties -- Proved Reserves," "Business and
Properties -- Production and Price History" and the Ryder Scott and Netherland,
Sewell reports included in this prospectus in evaluating the material presented
below. The historical data are those of Westport Oil and Gas and the pro forma
data were prepared as if the transaction between Westport Oil and Gas and EPGC
had taken place on January 1, 1999 for production, price and cost data and on
December 31, 1999 for reserve data.

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
--------------------------------------------- ------------------------------
THREE MONTHS
ENDED THREE MONTHS
YEAR ENDED DECEMBER 31, MARCH 31, YEAR ENDED ENDED
--------------------------- --------------- DECEMBER 31, MARCH 31,
1997 1998 1999 1999 2000 1999 2000
------- ------- ------- ------ ------ ------------ ---------------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (Mbbls)................ 3,114 3,483 3,300 859 794 3,893 901
Natural gas (Mmcf)......... 5,265 8,101 13,313 3,536 3,326 36,420 9,181
NGL (Mbbls)(1)............. -- -- -- -- -- 167 36
Total Mmcfe................ 23,949 28,999 33,113 8,690 8,090 60,779 14,805
AVERAGE PRICES(2):
Oil (per bbl).............. $ 17.35 $ 10.79 $ 16.45 $10.14 $26.36 $ 16.69 $ 26.38
Natural gas (per Mcf)...... 1.71 1.68 2.06 1.58 2.30 2.19 2.49
NGL (per bbl)(1)........... -- -- -- -- -- 11.22 23.10
Total per Mcfe............. 2.63 1.77 2.47 1.64 3.53 2.41 3.21
AVERAGE COSTS (PER MCFE):
Lease operating expense.... $ 0.82 $ 0.74 $ 0.69 $ 0.65 $ 0.82 $ 0.50 $ 0.53
General and
administrative........... 0.22 0.20 0.16 0.18 0.14(3) 0.13 0.13(3)
Depletion, depreciation and
amortization............. 0.99 1.25 0.76 0.98 0.76 0.96 1.10
</TABLE>

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

(1) Production of natural gas liquids was not meaningful for historical periods.

(2) Does not include the effects of hedging transactions.

(3) Does not include the effects of compensation expense of $3.4 million
recorded as a result of a repurchase of employee stock options in March 2000
in connection with the transaction between Westport Oil and Gas and EPGC.

6
<PAGE> 10

RESERVE REPLACEMENT DATA (FOR YEARS ENDED):
Production replacement ratio(2).................... 351% 273% 308% 256%
All-in finding costs per Mcfe(3)................... $ 1.78 $ 1.41 $ 0.14 $ 0.30
</TABLE>

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

(1) Calculated by dividing year-end proved reserves by annual production for the
period.

(2) Calculated by dividing reserve additions through acquisitions of reserves,
extensions and discoveries and revisions during the period by production for
such period (without dispositions, the production replacement ratio was
351%, 284%, 398% and 309%, respectively).

(3) Calculated by dividing costs incurred related to our oil and natural gas
producing activities during the period by total reserve additions for the
respective period. (See Note 12 of the Westport Oil and Gas consolidated
financial statements.)

7
<PAGE> 11

RISK FACTORS

Our material risks are described below. You should carefully consider these
risks before purchasing our common stock. If any of the following risks actually
occur, our business, financial condition or results of operations could be
materially adversely affected, the trading price of our common stock could
decline and you may lose all or part of your investment. Additional risks and
uncertainties, including those that are not yet identified or that we currently
think are immaterial, may adversely affect our business, financial condition or
results of operations.

RISKS RELATING TO OUR BUSINESS

OIL AND NATURAL GAS PRICES FLUCTUATE WIDELY, AND LOW PRICES COULD HAVE A
MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

Our revenues, operating results and future rate of growth are substantially
dependent upon the prevailing prices of, and demand for, oil and natural gas.
Declines in the prices of, or demand for, oil and natural gas may adversely
affect our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations. Lower oil and natural gas prices may
also reduce the amount of oil and natural gas that we can produce economically.
Historically, the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. During 1999 and 1998, the NYMEX
price for oil ranged from $11.99 to $26.09 per barrel and from $11.24 to $16.73
per barrel, respectively, and the Henry Hub price for natural gas ranged from
$1.65 to $3.07 per Mmbtu and from $1.00 to $2.65 per Mmbtu, respectively. Prices
for oil and natural gas are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for oil and natural gas,
market uncertainty and a variety of additional factors that are beyond our
control, including:

- worldwide and domestic supplies of oil and natural gas;

- the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil prices and production controls;

- political instability or armed conflict in oil-producing regions;

- the price and level of foreign imports;

- the level of consumer demand;

- the price and availability of alternative fuels;

- the availability of pipeline capacity;

- weather conditions;

- domestic and foreign governmental regulations and taxes; and

- the overall economic environment.

WE ARE VULNERABLE TO RISKS ASSOCIATED WITH OPERATING IN THE GULF OF MEXICO
BECAUSE A SUBSTANTIAL PORTION OF OUR EXPLORATION AND PRODUCTION ACTIVITIES IS
CONDUCTED IN THAT AREA.

Our operations and financial results are significantly impacted by
conditions in the Gulf of Mexico because we currently explore and produce
extensively in that area, including, in particular, our operations in the West
Cameron 180/198 complex, which accounts for over 30% of our daily production.
This concentration of activity makes us more vulnerable than some of our
competitors to the risks associated with operating in the Gulf of Mexico,
including those relating to:

- adverse weather conditions;

- oil field service costs and availability;

- compliance with environmental and other laws and regulations; and

- failure of equipment or facilities.

8
<PAGE> 12

In addition, some of our exploration is in the deep waters of the Gulf of
Mexico, where operations are more difficult and costly than in shallower waters.
The deep waters in the Gulf of Mexico lack the physical and oil field service
infrastructure present in the shallower waters of the Gulf of Mexico. As a
result, deep water operations may require a significant amount of time between a
discovery and the time that we can market the oil or natural gas, thereby
increasing the risk involved with these operations.

Further, production of reserves from reservoirs in the Gulf of Mexico
generally declines more rapidly than from reservoirs in many other producing
regions of the world. This results in recovery of a relatively higher percentage
of reserves from properties in the Gulf of Mexico during the initial few years
of production, and as a result, our reserve replacement needs from new prospects
are greater. Also, our revenues and return on capital will depend significantly
on prices prevailing during these relatively short production periods.

EXPLORATION IS A HIGH-RISK ACTIVITY. THE SEISMIC DATA AND OTHER ADVANCED
TECHNOLOGIES WE USE ARE EXPENSIVE AND CANNOT ELIMINATE EXPLORATION RISK.

Our future success depends in part on the success of our exploratory
drilling program. Poor results from our exploration activities could affect our
future results of operations and harm our financial condition. Exploration
activities involve numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be discovered. In addition, we
often are uncertain as to the future cost or timing of drilling, completing and
producing wells. Further, our drilling operations may be curtailed, delayed or
canceled as a result of a variety of factors, including:

- unexpected drilling conditions;

- title problems;

- pressure or irregularities in formations;

- equipment failures or accidents;

- adverse weather conditions;

- compliance with environmental and other governmental requirements; and

- cost of, or shortages or delays in the availability of, drilling rigs and
equipment.

We rely to a significant extent on seismic data and other advanced
technologies in conducting our exploration activities. Even when used and
properly interpreted, seismic data and visualization techniques only assist
geoscientists in identifying subsurface structures and hydrocarbon indicators.
They do not allow the interpreter to know conclusively if hydrocarbons are
present or economically producible. The use of seismic data and other
technologies also requires greater pre-drilling expenditures than traditional
drilling strategies. We could incur losses as a result of these expenditures.

THE FAILURE TO REPLACE OUR RESERVES WOULD ADVERSELY AFFECT OUR OPERATIONS AND
FINANCIAL CONDITION.

In general, the volume of production from oil and natural gas properties
declines as reserves are depleted. If we fail to replace our reserves, our
operations and financial condition could be adversely affected. Except to the
extent we acquire properties containing proved reserves or conduct successful
exploitation and exploration activities, our proved reserves will decline as
reserves are produced. Our future oil and natural gas production is, therefore,
highly dependent upon our success in finding or acquiring additional reserves at
attractive rates of return. In order to increase reserves and production, we
must continue development drilling and recompletion programs, pursue exploration
and drilling programs or undertake other replacement activities. Our current
strategy includes increasing our reserve base by continuing to exploit our
existing properties, by acquiring producing properties and by pursuing
exploration opportunities. We cannot assure you that our planned exploitation
and exploration projects and acquisition activities will result in significant
additional reserves or that we will have success in drilling productive wells at
favorable finding costs.
9
<PAGE> 13

RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN AND DEPEND ON ASSUMPTIONS THAT MAY BE
INACCURATE. ANY MATERIAL INACCURACIES IN OUR RESERVE ESTIMATES OR UNDERLYING
ASSUMPTIONS WILL AFFECT THE QUANTITIES AND PRESENT VALUES OF OUR RESERVES.

There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond our control. The reserve
information set forth in this prospectus represents estimates based on reports
prepared by independent petroleum engineers. Petroleum engineering is not an
exact science. Estimates of economically recoverable oil and natural gas
reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, any of which may cause these estimates to vary
considerably from actual results, such as:

- historical production from the area compared with production from other
producing areas;

- assumed effects of regulation by governmental agencies and assumptions
concerning future oil and natural gas prices;

- future operating costs;

- severance and excise taxes;

- capital expenditures; and

- workover and remedial costs.

Estimates of reserves based on risk of recovery and estimates of expected
future net cash flows prepared by different engineers, or by the same engineers
at different times, may vary substantially. Actual production, revenues and
expenditures with respect to our reserves will likely vary from estimates, and
the variance may be material.

The present values referred to in this prospectus should not be construed
as the current market value of the estimated oil and natural gas reserves
attributable to our properties. In accordance with requirements of the
Securities and Exchange Commission, or SEC, the estimated discounted net cash
flows from proved reserves are generally based on prices and costs as of the
date of the estimate, whereas actual future prices and costs may be materially
higher or lower. Actual future net cash flows will also be affected by factors
such as the amount and timing of actual production, supply and demand for oil
and natural gas, curtailments or increases in consumption by purchasers and
changes in governmental regulations or taxation. The timing of actual future net
cash flows from proved reserves, and thus their actual present value, will be
affected by the timing of both the production and the incurrence of expenses in
connection with exploitation and production of oil and natural gas properties.
In addition, the 10% discount factor required by the SEC to be used to calculate
discounted future net cash flows for reporting purposes is not necessarily the
most appropriate discount factor based on the interest rates in effect from time
to time and risks associated with our operations or the oil and natural gas
industry in general.

COMPETITION IN OUR INDUSTRY IS INTENSE, AND MANY OF OUR COMPETITORS HAVE GREATER
FINANCIAL, TECHNOLOGICAL AND OTHER RESOURCES THAN WE DO.

We operate in the highly competitive areas of oil and natural gas
exploitation, exploration and acquisition. The oil and natural gas industry is
characterized by rapid and significant technological advancements and
introductions of new products and services using new technologies. We face
intense competition from independent, technology-driven companies as well as
from both major and other independent oil and natural gas companies in each of
the following areas:

- seeking to acquire desirable producing properties or new leases for
future exploration;

- marketing our oil and natural gas production;

- integrating new technologies; and

- seeking to acquire the equipment and expertise necessary to develop and
operate our properties.

10
<PAGE> 14

Many of our competitors have financial, technological and other resources
substantially greater than ours. These companies may be able to pay more for
exploratory prospects and productive oil and natural gas properties and may be
able to define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Further, these
companies may enjoy technological advantages and may be able to implement new
technologies more rapidly than we can. Our ability to explore for oil and
natural gas prospects and to acquire additional properties in the future will
depend upon our ability to successfully conduct operations, implement advanced
technologies, evaluate and select suitable properties and consummate
transactions in this highly competitive environment.

WE ARE SUBJECT TO COMPLEX LAWS AND REGULATIONS, INCLUDING ENVIRONMENTAL
REGULATIONS, THAT CAN ADVERSELY AFFECT THE COST, MANNER OR FEASIBILITY OF DOING
BUSINESS.

Exploration for and exploitation, production and sale of oil and natural
gas in the United States, and especially in the Gulf of Mexico, are subject to
extensive Federal, state and local laws and regulations, including complex tax
laws and environmental laws and regulations. These laws, and their
interpretation, are subject to change, the effects of which cannot be predicted.
We cannot assure you that existing laws or regulations, as currently interpreted
or reinterpreted in the future, or future laws or regulations will not harm our
business, results of operations and financial condition. We may be required to
make large expenditures to comply with environmental and other governmental
regulations. Matters subject to regulation include:

- discharge permits for drilling operations;

- drilling bonds;

- spacing of wells;

- unitization and pooling of properties;

- environmental protection;

- reports concerning operations; and

- taxation.

Under these laws and regulations, we could be liable for:

- personal injuries;

- property damage;

- oil spills;

- discharge of hazardous materials;

- well reclamation costs;

- remediation and clean-up costs; and

- other environmental damages.

While we maintain insurance coverage for our operations, we do not believe
that full insurance coverage for all potential environmental damages is
available at a reasonable cost. Failure to comply with these laws and
regulations also may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Further, these
laws and regulations could change in ways that substantially increase our costs.
For example, Congress or the Minerals Management Service, a bureau of the U.S.
Department of the Interior responsible for managing the mineral resources on the
Outer Continental Shelf, could decide to limit exploratory drilling or natural
gas production in some areas of the Gulf of Mexico or other geographic regions
in which we operate. Any of these liabilities, penalties,

11
<PAGE> 15

suspensions, terminations or regulatory changes could have a material adverse
affect on our financial condition and results of operations.

WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE.

Other companies operate some of the properties in which we have an
interest. As a result, we have limited ability to exercise influence over
operations for these properties or their associated costs. Our dependence on the
operator and other working interest owners for these projects and our limited
ability to influence operations and associated costs could materially adversely
affect the realization of our targeted returns on capital in drilling or
acquisition activities. The success and timing of our drilling and exploitation
activities on properties operated by others therefore depend upon a number of
factors that are outside of our control, including:

- timing and amount of capital expenditures;

- the operator's expertise and financial resources;

- approval of other participants in drilling wells; and

- selection of technology.

OUR BUSINESS INVOLVES MANY OPERATING RISKS WHICH MAY RESULT IN SUBSTANTIAL
LOSSES. INSURANCE MAY BE UNAVAILABLE OR INADEQUATE TO PROTECT US AGAINST THESE
RISKS.

Our operations are subject to hazards and risks inherent in drilling for,
producing and transporting oil and natural gas, such as:

- fires;

- natural disasters;

- explosions;

- formations with abnormal pressures;

- casing collapses;

- embedded oilfield drilling and service tools;

- uncontrollable flows of underground natural gas, oil and formation water;

- blowouts;

- surface cratering;

- pipeline ruptures or cement failures; and

- environmental hazards such as natural gas leaks, oil spills and
discharges of toxic gases.

Any of these risks can cause substantial losses resulting from:

- injury or loss of life;

- damage to and destruction of property, natural resources and equipment;

- pollution and other environmental damage;

- regulatory investigations and penalties;

- suspension of our operations; and

- repair and remediation costs.

12
<PAGE> 16

In addition, offshore operations are subject to a variety of operating
risks peculiar to the marine environment, such as capsizing, collisions and
damage or loss from hurricanes or other adverse weather conditions. These
conditions can cause substantial damage to our facilities and could interrupt
production. If we experience any of these problems, our business and operations
may be harmed and our ability to acquire, explore and develop properties may be
reduced or eliminated.

As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. We believe that our insurance is
adequate and customary for companies of a similar size engaged in operations
similar to ours, but losses could occur for uninsurable or uninsured risks, or
in amounts in excess of existing insurance coverage. The occurrence of an event
that is not fully covered by insurance could harm our financial condition and
results of operations.

OUR EXPLOITATION, ACQUISITION AND EXPLORATION OPERATIONS REQUIRE SUBSTANTIAL
CAPITAL, AND WE MAY BE UNABLE TO OBTAIN NEEDED FINANCING ON SATISFACTORY TERMS.

We make and will continue to make substantial capital expenditures in
exploitation, acquisition and exploration projects. We intend to finance these
capital expenditures with cash flow from operations and our existing financing
arrangements. Additional financing sources may be required in the future to fund
our developmental and exploratory drilling. We cannot assure you that financing
will continue to be available under existing or new financing arrangements, or
that we will be able to obtain necessary financing on acceptable terms, if at
all. If additional capital resources are not available, we may be forced to
curtail our drilling, acquisition and other activities or be forced to sell some
of our assets on an untimely or unfavorable basis.

THE ACQUISITION OF OIL AND NATURAL GAS PROPERTIES IMPOSES SUBSTANTIAL RISKS.

We constantly evaluate acquisition opportunities and frequently engage in
bidding and negotiation for acquisitions, many of which are substantial. If
successful in this process, we may be required to alter or increase
substantially our capitalization to finance these acquisitions through the use
of cash on hand, issuance of additional debt or equity securities, the sale of
production payments, borrowing of additional funds or otherwise. Our existing
credit agreement includes covenants limiting our ability to incur additional
indebtedness. If we were to proceed with one or more acquisitions for stock, our
stockholders would suffer dilution of their interests. These additional
capitalization requirements may significantly affect our risk profile. The
acquisition of properties that are substantially different in operating or
geologic characteristics or geographic locations from our existing properties
could change the nature of our operations and business. While we intend to
concentrate on acquiring producing properties with exploitation and exploration
potential located in our current areas of operation, we may decide to acquire
properties located in other geographic regions. We can give you no assurance
that we will be successful in identifying or acquiring any material property
interests.

WE MAY NOT REALIZE THE BENEFITS OF INTEGRATING WITH THE GULF OF MEXICO
OPERATIONS ACQUIRED IN THE TRANSACTION BETWEEN WESTPORT OIL AND GAS AND EPGC OR
BE SUCCESSFUL IN MANAGING OUR COMBINED COMPANY.

The transaction between Westport Oil and Gas and EPGC was consummated on
April 7, 2000. As a result of the transaction, the senior management team of
Westport Oil and Gas became the management team for the combined company,
complemented by certain key managers from EPGC. Unless our management is
successful in integrating and managing the employees and assets acquired in the
transaction with EPGC in a cost-efficient manner, we will not be able to realize
or maintain the operating efficiencies and other benefits sought from the
transaction. We cannot assure you that we will be able to successfully integrate
properties and operations of Westport Oil and Gas with those acquired in the
transaction with EPGC, or that we can successfully manage the combined company,
and the failure to do so could harm our business.

13
<PAGE> 17

HEDGING OUR PRODUCTION MAY RESULT IN LOSSES.

To reduce our exposure to fluctuations in the prices of oil and natural
gas, we currently and may in the future enter into hedging arrangements. Hedging
arrangements expose us to risk of financial loss in some circumstances,
including the following:

- production is less than expected;

- the counter-party to the hedging contract defaults on its contract
obligations; or

- there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received.

In addition, these hedging arrangements may limit the benefit we would receive
from increases in the prices for oil and natural gas.

OUR OPERATIONS REQUIRE US TO ATTRACT AND RETAIN EXPERIENCED TECHNICAL PERSONNEL.

Our exploratory drilling success depends, in part, on our ability to
attract and retain experienced explorationists and other professional personnel.
We currently employ 24 explorationists and engineers, two engineering
consultants and seven geology/geophysical consultants, all of whom have
experience in the geographic areas to which we have assigned them. Competition
for experienced explorationists and engineers is extremely intense. If we cannot
retain these personnel or attract additional experienced personnel, our ability
to compete in the geographic regions in which we conduct our operations could be
harmed.

THE LOSS OF OUR CHIEF EXECUTIVE OFFICER OR OTHER KEY PERSONNEL COULD ADVERSELY
AFFECT US.

We depend to a large extent on the efforts and continued employment of
Donald D. Wolf, our chief executive officer and chairman, Barth E. Whitham, our
president and chief operating officer, and other key personnel. The loss of the
services of Messrs. Wolf or Whitham or other key personnel could adversely
affect our business. In addition, it is a default under our credit agreement if
both Mr. Wolf and Mr. Whitham cease to act in their current capacities as
officers of Westport.

THE MARKETABILITY OF OUR PRODUCTION IS DEPENDENT UPON FACTORS OVER WHICH WE HAVE
NO CONTROL.

The marketability of our production depends in part upon the availability,
proximity and capacity of pipelines, natural gas gathering systems and
processing facilities. Any significant change in market factors affecting these
infrastructure facilities could harm our business, financial condition and
results of operations. We deliver oil and natural gas through gathering systems
and pipelines that we do not own. We can give you no assurance that these
facilities will be available to us in the future. Our ability to produce and
market oil and natural gas are affected and may be also harmed by:

- Federal and state regulation of oil and natural gas production;

- transportation, tax and energy policies;

- changes in supply and demand; and

- general economic conditions.

RISKS RELATING TO THIS OFFERING

OUR PRINCIPAL STOCKHOLDERS OWN A SIGNIFICANT AMOUNT OF COMMON STOCK, GIVING THEM
A CONTROLLING INFLUENCE OVER CORPORATE TRANSACTIONS AND OTHER MATTERS.

Upon completion of this offering, Westport Energy LLC (formerly Westport
Energy Corporation) and ERI Investments, Inc. (an affiliate of Equitable
Production Company), our principal stockholders, will beneficially own
approximately % of our outstanding common stock (approximately % if
the underwriters exercise their over-allotment option in full). Accordingly,
these stockholders, acting together,

14
<PAGE> 18

will be able to control the outcome of stockholder votes, including votes
concerning the election of directors, the adoption or amendment of provisions in
our certificate of incorporation or bylaws and the approval of mergers and other
significant corporate transactions. This concentrated ownership makes it
unlikely that any other holder or group of holders of common stock will be able
to affect the way we are managed or the direction of our business. These factors
may also delay or prevent a change in the management or voting control of
Westport.

In addition, we entered into an agreement with our principal stockholders
in connection with the transaction with EPGC that allows these stockholders to
maintain their position of control by, among other things, addressing how these
stockholders will vote their shares in the election of directors.

THERE HAS NEVER BEEN A PUBLIC MARKET FOR OUR COMMON STOCK, AND OUR STOCK PRICE
MAY FLUCTUATE SIGNIFICANTLY.

Before this offering, there has been no public market for our common stock,
and an active trading market may not develop or be sustained. The initial public
offering price of our common stock will be determined by negotiation between us
and the representatives of the underwriters and may bear no relationship to the
market price of our common stock after this offering. The trading price of our
common stock, and the price at which we may sell securities in the future, could
be subject to significant fluctuations in response to government regulations,
variations in quarterly operating results, the prices of oil and natural gas and
other factors.

WE HAVE NOT PAID DIVIDENDS AND DO NOT ANTICIPATE PAYING ANY DIVIDENDS ON OUR
COMMON STOCK IN THE FORESEEABLE FUTURE.

We anticipate that we will retain all future earnings and other cash
resources for the future operation and development of our business. Accordingly,
we do not intend to declare or pay any cash dividends in the foreseeable future.
Payment of any future dividends will be at the discretion of our board of
directors after taking into account many factors, including our operating
results, financial condition, current and anticipated cash needs and plans for
expansion. The declaration and payment of any future dividends also may be
restricted by agreements with our lenders.

OUR CERTIFICATE OF INCORPORATION CONTAINS PROVISIONS THAT COULD DISCOURAGE AN
ACQUISITION OR CHANGE OF CONTROL OF WESTPORT.

Our certificate of incorporation authorizes the issuance of preferred stock
without stockholder approval. Our board of directors has the power to determine
the price and terms of any preferred stock. The ability of our board of
directors to issue one or more series of preferred stock without stockholder
approval could deter or delay unsolicited changes of control by discouraging
open market purchases of our common stock or a non-negotiated tender or exchange
offer for our common stock. Discouraging open market purchases may be
disadvantageous to our stockholders who may otherwise desire to participate in a
transaction in which they would receive a premium for their shares.

In addition, some provisions of our certificate of incorporation and bylaws
may also discourage a change of control by means of a tender offer, open market
purchase, proxy contest or otherwise. These provisions include:

- a board that is divided into three classes, which are elected to serve
staggered three-year terms;

- provisions under which only our chairman or our president or secretary
may call a special meeting of the stockholders;

- provisions that permit our board of directors to increase the number of
directors and to fill these positions without a vote of the stockholders;

- provisions under which no director may be removed at any time except for
cause and by a majority vote of the board of directors and of the
outstanding shares of voting stock; and

- provisions under which stockholder action may be taken only at a
stockholders meeting and not by written consent of the stockholders.

15
<PAGE> 19

These provisions may have the effect of discouraging takeovers, even if the
change of control might be beneficial to our stockholders.

INVESTORS IN THIS OFFERING WILL SUFFER IMMEDIATE AND SUBSTANTIAL DILUTION.

If you purchase common stock in this offering, you will experience
immediate and substantial dilution of $ per share, based upon an assumed
initial public offering price of $ per share, because the price you pay will
be substantially greater than the net tangible book value per share of $ for
the shares you acquire. This dilution is due in large part to the fact that
prior investors paid an average price of $ per share when they purchased
their shares of common stock, which is substantially less than the anticipated
initial public offering price.

FUTURE SALES OF OUR COMMON STOCK MAY DEPRESS OUR STOCK PRICE.

Sales of a substantial number of shares of our common stock in the public
market after this offering, or the perception that these sales may occur, could
cause the market price of our common stock to decline. In addition, the sale of
these shares could impair our ability to raise capital through the sale of
additional common or preferred stock.

After this offering, we will have shares of common stock
outstanding. Of these shares, all shares sold in the offering, other than
shares, if any, purchased by our affiliates, will be freely tradable. All of the
holders of our common stock are subject to agreements that limit their ability
to sell their common stock. These holders cannot sell or otherwise dispose of
any shares of common stock for a period of at least 180 days after the date of
this prospectus without the prior written approval of Credit Suisse First Boston
Corporation, which could, in its sole discretion, elect to permit resale of
shares by existing stockholders prior to the lapse of the 180-day period.

16
<PAGE> 20

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Our disclosure and analysis in this prospectus contain some forward-looking
statements. Forward-looking statements give our current expectations or
forecasts of future events. You can identify these statements by the fact that
they do not relate strictly to historical or current facts. These statements may
include words such as "anticipate," "estimate," "expect," "project," "intend,"
"plan," "believe" and other words and terms of similar meaning in connection
with any discussion of future operating or financial performance. In particular,
these include, among other things, statements relating to:

- amount, nature and timing of capital expenditures;

- drilling of wells;

- timing and amount of future production of oil and natural gas;

- operating costs and other expenses;

- cash flow and anticipated liquidity;

- prospect exploitation and property acquisitions; and

- marketing of oil and natural gas.

Any or all of our forward-looking statements in this prospectus may turn
out to be wrong. They can be affected by inaccurate assumptions we might make or
by known or unknown risks and uncertainties. Many factors mentioned in our
discussion in this prospectus, including the risks outlined under "Risk
Factors," will be important in determining future results. Actual future results
may vary materially. Factors that could cause our results to differ materially
from the results discussed in the forward-looking statements include the risks
described under "Risk Factors," including:

- the risks associated with exploration;

- our ability to find, acquire, market, develop and produce new properties;

- oil and natural gas price volatility;

- uncertainties in the estimation of proved reserves and in the projection
of future rates of production and timing of exploitation expenditures;

- operating hazards attendant to the oil and natural gas business;

- drilling and completion risks that are generally not recoverable from
third parties or insurance;

- potential mechanical failure or underperformance of significant wells;

- climatic conditions;

- availability and cost of material and equipment;

- actions or inactions of third-party operators of our properties;

- our ability to find and retain skilled personnel;

- availability of capital;

- the strength and financial resources of our competitors;

- regulatory developments;

- environmental risks; and

- general economic conditions.

When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this prospectus. Our
forward-looking statements speak only as of the date made.

17
<PAGE> 21

USE OF PROCEEDS

We estimate that the net proceeds from our sale of shares of common
stock will be approximately $ million, assuming an initial public offering
price of $ per share and after deducting underwriting discounts and
commissions and estimated offering expenses. We intend to use the net proceeds
from the offering for repayment of a portion of the debt under our credit
agreement. We will use the increased borrowing capacity under the credit
agreement, along with cash flow from operations, to pursue exploitation,
acquisition and exploration activities and for general corporate purposes.

We will not receive any proceeds from the sale of common stock offered by
the selling stockholders, including those shares that may be sold by the selling
stockholders if the underwriters exercise their over-allotment option.

The credit agreement terminates on April 4, 2003 and the entire unpaid
principal balance and accrued interest is due and payable on that date. At March
31, 2000, the average interest rate on borrowings under the credit agreement was
approximately 8.2% per annum. Approximately $50 million of the initial
borrowings under the credit agreement were used to pay the cash portion of the
purchase price in connection with the transaction with EPGC and $105.5 million
was used to refinance indebtedness under a previous credit facility. The
remainder of the borrowings under the credit agreement has been used for working
capital and general corporate purposes.

DIVIDEND POLICY

We have never declared or paid any cash dividends on our common stock. We
anticipate that we will retain all future earnings and other cash resources for
investment in our business. Accordingly, we do not intend to declare or pay cash
dividends in the foreseeable future. Payment of any future dividends will be at
the discretion of our board of directors after taking into account many factors,
including our financial condition, operating results, current and anticipated
cash needs and plans for expansion. In addition, our ability to declare and pay
any dividends is now and may in the future be restricted by agreements with our
lenders.

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<PAGE> 22

DILUTION

Our net tangible book value as of March 31, 2000 was approximately $
million, or $ per share of common stock. Net tangible book value per share
as of any date represents the amount of total tangible assets less total
liabilities as of such date, divided by the number of shares of common stock
then outstanding. Without taking into account any changes in the net tangible
book value after March 31, 2000, other than to give effect to our sale of the
shares of common stock offered hereby and our receipt of the estimated
net proceeds therefrom, our as adjusted net tangible book value as of March 31,
2000 would have been approximately $ million, or $ per share of common
stock. This represents an immediate increase in net tangible book value of
$ per share to existing stockholders and an immediate dilution of $ per
share to new investors. The following table illustrates this dilution:

<TABLE>
<CAPTION>
PER SHARE
-----------------
<S> <C> <C>
Assumed initial public offering price....................... $
Net tangible book value before this offering.............. $
Increase attributable to new investors....................
-------
As adjusted net tangible book value after this offering.....
-------
Dilution to new investors................................. $
=======
</TABLE>

The following table summarizes, on an as adjusted basis as of March 31,
2000, the differences between existing stockholders and the new investors with
respect to the number of shares of common stock purchased from us and the
selling stockholders, the total consideration paid and the average price per
share paid before deducting the underwriting discounts and commissions and
estimated offering expenses payable by us.

<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE
------------------- ------------------- PRICE PER
NUMBER PERCENT AMOUNT PERCENT SHARE
--------- ------- --------- ------- ---------
<S> <C> <C> <C> <C> <C>
Existing stockholders........................ % $ % $
New investors................................
--------- --- --------- ---
Total.............................. % $ 100%
========= === ========= ===
</TABLE>

The table does not include shares of common stock reserved for
issuance under our stock option plan, of which have been granted.

19
<PAGE> 23

CAPITALIZATION

The following table sets forth our capitalization as of March 31, 2000. Our
capitalization is presented on:

- an actual basis;

- a pro forma basis, giving effect to the EPGC transaction; and

- a pro forma as adjusted basis to give further effect to:

- the sale by us of shares of common stock in the offering at an
assumed initial public offering price of $ per share, after
deducting underwriting discounts and estimated offering expenses, and

- the application by us of the proceeds of that sale to repay a portion of
the debt under our credit agreement.

The following table should be read in conjunction with our financial statements
and the related notes, and the other information contained elsewhere in this
prospectus, including the information set forth in "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

<TABLE>
<CAPTION>
MARCH 31, 2000
----------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- --------- -----------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C>
Cash........................................................ $ 12,238 $ 19,836 $
-------- -------- --------
Short-term debt............................................. $ 1,000 $ 1,000 $
======== ======== ========
LONG-TERM DEBT:
Credit agreement.......................................... $105,462 $155,462 $
-------- -------- --------
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value (5,000,000 shares
authorized and no shares outstanding actual, pro forma
or pro forma as adjusted).............................. -- -- --
Common stock, $0.01 par value (12,000,000 shares
authorized and 10,420,334 shares outstanding actual;
30,000,000 shares authorized and 20,577,769 shares
outstanding pro forma; shares authorized and
shares outstanding pro forma as adjusted)....... 3 206
Additional paid-in capital................................ 198,448 366,496
Accumulated deficit....................................... (57,043) (57,043)
-------- -------- --------
Total stockholders' equity................................ 141,408 309,659
-------- -------- --------
Total capitalization.............................. $246,870 $465,121 $
======== ======== ========
</TABLE>

20
<PAGE> 24

SELECTED CONSOLIDATED FINANCIAL DATA

You should read the following selected consolidated financial data along
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our consolidated financial statements and the related notes,
each of which is included in this prospectus. We derived the statement of
operations data for the three-year period ended December 31, 1999 and the
balance sheet data as of December 31, 1998 and 1999 from the consolidated
financial statements of Westport Oil and Gas, which have been audited by Arthur
Andersen LLP, independent accountants, and are included in this prospectus. We
derived the statement of operations data for the year ended December 31, 1996
and the balance sheet data as of December 31, 1996 and 1997 from the audited
consolidated financial statements of Westport Oil and Gas, which are not
included in this prospectus. We derived the statement of operations data for the
year ended December 31, 1995 and the balance sheet data as of December 31, 1995
from the unaudited consolidated financial statements of Westport Oil and Gas,
which are not included in this prospectus. We derived the statement of
operations data for the three-month periods ended March 31, 1999 and 2000 from
the unaudited consolidated financial statements of Westport Oil and Gas, which
are included in this prospectus. In the opinion of our management, the unaudited
financial information includes all adjustments, consisting of only normal
recurring adjustments, considered necessary for a fair presentation of that
information. Our results of operations for the three-month period ended March
31, 2000 are not necessarily indicative of the results that we may achieve for
the entire year.

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------------------ -------------------
1995 1996 1997 1998 1999 1999 2000
-------- -------- --------- --------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Revenues................... $ 19,446 $ 35,141 $ 63,089 $ 51,505 $ 73,763 $ 14,978 $ 24,985
Operating costs and
expenses:
Lease operating
expense................ 5,787 10,716 19,583 21,554 22,916 5,620 6,623
Production taxes......... 1,873 3,561 5,923 3,888 5,742 798 2,268
Exploration.............. 1,102 1,054 7,424 14,664 7,314 1,038 1,871
Depletion, depreciation
and amortization....... 5,888 8,325 23,659 36,264 25,210 8,489 6,172
Impairment of proved
properties............. -- 442 5,765 8,794 3,072 -- --
Impairment of unproved
properties............. -- -- 380 1,898 2,273 -- 235
General and
administrative......... 1,184 2,655 5,316 5,913 5,297 1,580 4,547(1)
-------- -------- --------- --------- -------- -------- --------
Total operating
expenses........ 15,834 26,753 68,050 92,975 71,824 17,525 21,716
-------- -------- --------- --------- -------- -------- --------
Operating income
(loss).......... 3,612 8,388 (4,961) (41,470) 1,939 (2,547) 3,269
Other income (expense):
Interest expense......... (2,307) (2,774) (5,635) (8,323) (9,207) (2,497) (2,047)
Interest income.......... 116 313 309 403 489 99 193
Gain (loss) on sale of
assets -- net.......... -- 128 (13) -- 3,637 4,770 (17)
Other.................... 7 44 (54) 29 16 16 (1)
-------- -------- --------- --------- -------- -------- --------
Income (loss) before income
taxes.................... 1,428 6,099 (10,354) (49,361) (3,126) (159) 1,397
Benefit (provision) for
income taxes............. -- (2,289) 973 -- -- -- --
-------- -------- --------- --------- -------- -------- --------
Net income (loss).......... $ 1,428 $ 3,810 $ (9,381) $ (49,361) $ (3,126) $ (159) $ 1,397
======== ======== ========= ========= ======== ======== ========
</TABLE>

21
<PAGE> 25

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------------------ -------------------
1995 1996 1997 1998 1999 1999 2000
-------- -------- --------- --------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES
OUTSTANDING:
Basic.................... 3,000 3,021 6,217 7,336 9,818 9,054 10,420
======== ======== ========= ========= ======== ======== ========
Diluted.................. 3,000 3,021 6,217 7,336 9,818 9,054 10,616
======== ======== ========= ========= ======== ======== ========
NET INCOME (LOSS) PER
COMMON SHARE:
Basic.................... $ 0.48 $ 1.26 $ (1.51) $ (6.73) $ (0.32) $ (0.02) $ 0.13
======== ======== ========= ========= ======== ======== ========
Diluted.................. $ 0.48 $ 1.26 $ (1.51) $ (6.73) $ (0.32) $ (0.02) $ 0.13
======== ======== ========= ========= ======== ======== ========
OTHER FINANCIAL DATA:
Adjusted EBITDA(2)......... $ 10,725 $ 18,694 $ 32,509 $ 20,582 $ 43,950 $ 11,865 $ 11,722
Net cash provided by
operating activities..... 12,144 15,921 26,117 10,458 25,110 895 5,215
Net cash provided by (used
in) investing
activities............... (70,279) (24,040) (152,412) (115,855) 14,150 23,325 (12,119)
Net cash provided by (used
in) financing
activities............... 62,200 13,735 126,675 104,667 (29,933) (14,333) (333)
Capital expenditures....... 70,279 24,023 155,762 115,844 17,836 333 12,110
BALANCE SHEET DATA (AS OF
PERIOD END):
Cash....................... $ 4,881 $ 10,497 $ 10,878 $ 10,148 $ 19,475 $ 20,035 $ 12,238
Working capital
(deficit)................ (1,490) 7,685 4,296 (30,993) 12,837 (3,020) 9,557
Total assets............... 95,838 117,550 245,394 302,302 271,477 286,801 269,503
Total long-term debt....... 26,625 25,462 92,128 121,333 105,462 121,000 105,462
Total debt................. 34,125 26,795 93,462 153,128 106,795 138,795 106,462
Stockholders' equity....... 55,596 80,471 131,098 126,737 140,011 126,577 141,408
</TABLE>

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

(1) Includes compensation expenses of $3.4 million recorded as a result of a
repurchase of employee stock options in March 2000 in connection with the
transaction between Westport Oil and Gas and EPGC.

22
<PAGE> 26

UNAUDITED PRO FORMA FINANCIAL STATEMENTS
OF WESTPORT RESOURCES CORPORATION

The following unaudited pro forma condensed consolidated balance sheet as
of March 31, 2000, and pro forma condensed consolidated statements of operations
for the year ended December 31, 1999 and the three months ended March 31, 2000,
adjust the historical financial information of Westport Oil and Gas to reflect
the transaction between Westport Oil and Gas and EPGC that was consummated on
April 7, 2000. The pro forma balance sheet was prepared as if the acquisition
was consummated on March 31, 2000. The pro forma statements of operations were
prepared as if the acquisition was consummated on January 1, 1999. The pro forma
adjustments are based on estimates and assumptions explained in further detail
in the accompanying notes.

The unaudited pro forma financial statements should be read in conjunction
with the accompanying notes and the historical financial statements and related
notes of Westport Oil and Gas and the historical statements of revenues and
direct operating expenses and related notes for the acquired EPGC properties,
each of which is included in this prospectus. The pro forma information
presented does not purport to be indicative of the financial position or results
of operations that would have actually occurred had the acquisition been
consummated on the dates indicated or which may occur in the future.

23
<PAGE> 27

WESTPORT RESOURCES CORPORATION

UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
HISTORICAL
WESTPORT OIL PRO FORMA
AND GAS ADJUSTMENTS PRO FORMA
------------ ----------- ---------
<S> <C> <C> <C>
Revenues................................................ $73,763 $64,872 (A) $138,635
------- ------- --------
Operating costs and expenses:
Lease operating expense............................... 22,916 7,215 (A) 30,131
Production taxes...................................... 5,742 -- 5,742
Exploration........................................... 7,314 -- 7,314
Depletion, depreciation and amortization.............. 25,210 33,088 (B) 58,298
Impairment of proved properties....................... 3,072 -- 3,072
Impairment of unproved properties..................... 2,273 -- 2,273
General and administrative............................ 5,297 2,807 (C) 8,104
------- ------- --------
Total operating expenses...................... 71,824 43,110 114,934
------- ------- --------
Operating income.............................. 1,939 21,762 23,701
------- ------- --------
Other income (expense):
Interest expense...................................... (9,207) (4,094)(D) (13,301)
Interest income....................................... 489 -- 489
Gain on sale of assets -- net......................... 3,637 -- 3,637
Other................................................. 16 -- 16
------- ------- --------
Income (loss) before income taxes....................... (3,126) 17,668 14,542
Provision for income taxes.............................. -- (5,090)(E) (5,090)
------- ------- --------
Net income (loss)....................................... $(3,126) $12,578 $ 9,452
======= ======= ========
Weighted average number of common shares outstanding:
Basic................................................. 9,818 10,158 (F) 19,976
======= ======= ========
Diluted............................................... 9,818 10,249 (F) 20,067
======= ======= ========
Net income (loss) per common share:
Basic................................................. $ (0.32) $ 0.47
======= ========
Diluted............................................... $ (0.32) $ 0.47
======= ========
</TABLE>

The accompanying notes to the unaudited pro forma condensed consolidated
financial statements are an integral part of these statements.

24
<PAGE> 28

WESTPORT RESOURCES CORPORATION

UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2000
(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
HISTORICAL
WESTPORT OIL PRO FORMA
AND GAS ADJUSTMENTS PRO FORMA
------------ ----------- ---------
<S> <C> <C> <C>
Revenues................................................ $24,985 $18,932 (A) $43,917
------- ------- -------
Operating costs and expenses:
Lease operating expense............................... 6,623 1,215 (A) 7,838
Production taxes...................................... 2,268 -- 2,268
Exploration........................................... 1,871 -- 1,871
Depletion, depreciation and amortization.............. 6,172 10,126 (B) 16,298
Impairment of unproved properties..................... 235 -- 235
General and administrative............................ 4,547 702 (C) 5,249
------- ------- -------
Total operating expenses...................... 21,716 12,043 33,759
------- ------- -------
Operating income.............................. 3,269 6,889 10,158
------- ------- -------
Other income (expense):
Interest expense...................................... (2,047) (1,023)(D) (3,070)
Interest income....................................... 193 -- 193
Loss on sale of assets -- net......................... (17) -- (17)
Other................................................. (1) -- (1)
------- ------- -------
Income before income taxes.............................. 1,397 5,866 7,263
Provision for income taxes.............................. -- (2,542)(E) (2,542)
------- ------- -------
Net income.............................................. $ 1,397 $ 3,324 $ 4,721
======= ======= =======
Weighted average number of common shares outstanding:
Basic................................................. 10,420 10,158 (F) 20,578
======= ======= =======
Diluted............................................... 10,616 10,158 (F) 20,774
======= ======= =======
Net income per common share:
Basic................................................. $ 0.13 $ 0.23
======= =======
Diluted............................................... $ 0.13 $ 0.23
======= =======
</TABLE>

The accompanying notes to the unaudited pro forma condensed consolidated
financial statements are an integral part of these statements.

25
<PAGE> 29

WESTPORT RESOURCES CORPORATION

UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED BALANCE SHEET
MARCH 31, 2000
(IN THOUSANDS)

<TABLE>
<CAPTION>
HISTORICAL
WESTPORT OIL PRO FORMA
AND GAS ADJUSTMENTS PRO FORMA
------------ ----------- ---------
<S> <C> <C> <C>
ASSETS

Current assets.......................................... $ 29,590 $ 17,143 (I) $ 46,733
-------- -------- --------
Property and equipment, at cost:
Oil and gas properties, successful efforts method:
Proved properties.................................. 316,684 193,603 (G) 509,368
11,195 (H)
(15,009)(I)
2,895 (J)
Unproved properties................................ 18,749 23,603 (G) 42,352
Office furniture, equipment and other................. 2,723 -- 2,723
-------- -------- --------
338,156 216,287 554,443
Less accumulated depletion, depreciation and
amortization.......................................... (99,070) -- (99,070)
-------- -------- --------
Net property and equipment.................... 239,086 216,287 455,373
-------- -------- --------
Other assets............................................ 827 -- 827
-------- -------- --------
Total assets.................................. $269,503 $233,430 $502,933
======== ======== ========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities..................................... $ 20,034 $ 1,850 (G) $ 24,018
2,134 (I)
Long-term debt.......................................... 105,462 50,000 (G) 155,462
Other liabilities....................................... 2,599 11,195 (H) 13,794
-------- -------- --------
Total liabilities............................. 128,095 65,179 193,274
-------- -------- --------
Stockholders' equity.................................... 141,408 165,356 (G) 309,659
2,895 (J)
-------- -------- --------
Total liabilities and stockholders' equity.... $269,503 $233,430 $502,933
======== ======== ========
</TABLE>

The accompanying notes to the unaudited pro forma condensed consolidated
financial statements are an integral part of this balance sheet.

26
<PAGE> 30

WESTPORT RESOURCES CORPORATION

NOTES TO UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
(IN THOUSANDS, EXCEPT SHARE DATA)

(A) Adjustment to reflect the historical revenues and direct operating
expenses attributable to the EPGC properties.

(B) Adjustment to reflect additional depletion, depreciation and amortization
expense resulting from the EPGC properties. The additional pro forma
depletion, depreciation and amortization expense is computed based on the
portion of the purchase price and transaction costs allocated to proved
properties and using the units of production depletion method based on
estimates of proved reserves for the EPGC properties as of the beginning
of each period presented.

(C) Adjustment to reflect estimated general and administrative expenses
related to EPGC employees retained by Westport in connection with the
transaction between Westport Oil and Gas and EPGC.

(D) Adjustment to reflect additional interest expense related to debt incurred
to finance the transaction between Westport Oil and Gas and EPGC. The
interest rate used was Westport Oil and Gas' effective rate of 8.2% at
April 7, 2000.

(E) Adjustment to reflect the provision for income taxes resulting from pro
forma income before income taxes, assuming an effective tax rate of 35%.

(F) Adjustment to reflect in the 1999 and 2000 periods the issuance of
10,157,435 shares of Westport common stock in connection with the
transaction between Westport Oil and Gas and EPGC, and, in the 1999
period, the impact of common stock equivalents which become dilutive on a
pro forma basis in 1999.

(G) Adjustment to reflect the cost of oil and gas properties acquired,
liabilities assumed and additional debt incurred to finance the
transaction between Westport Oil and Gas and EPGC as follows:

<TABLE>
<CAPTION>
PRO FORMA
ADJUSTMENTS
-----------
<S> <C>
Acquisition Costs:
Common stock issued.................................... $165,356
Cash paid/Long-term debt incurred...................... 50,000
Liabilities assumed.................................... 1,850
--------
Total acquisition costs........................ $217,206
========
Allocation of Acquisition Costs:
Oil and gas properties -- proved....................... $193,603
Oil and gas properties -- unproved..................... 23,603
--------
Total allocation............................... $217,206
========
</TABLE>

(H) Adjustment to reflect deferred taxes resulting from the difference between
the pro forma book basis and tax basis of oil and gas properties.

(I) Adjustment to reflect purchase price adjustments resulting from activity
subsequent to the effective date of the transaction between Westport Oil
and Gas and EPGC.

(J) Adjustment to reflect the accounting impact of payment by Westport Energy
LLC (Westport Oil and Gas' principal shareholder) for transaction fees
related to the transaction between Westport Oil and Gas and EPGC.

27
<PAGE> 31

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

GENERAL

Acquisitions over the past three years have facilitated our growth. On
April 7, 2000, Westport Oil and Gas consummated a transaction with EPGC pursuant
to which Westport Oil and Gas was combined with certain Gulf of Mexico assets of
EPGC. In connection with this transaction we issued 10.2 million shares of
common stock, paid cash of $50.0 million and assumed debt of $1.8 million. We
increased our proved reserves by 138.7 Bcfe, our Gulf of Mexico leasehold by
157,000 net acres, and our daily production by 74 Mmcfe, helping to bring total
daily production for the first quarter 2000 to 163 Mmcfe. On October 15, 1998,
Westport Oil and Gas acquired an undivided 31% interest in the assets of Total
Minatome Corporation for a total purchase price of $56.0 million. The oil and
natural gas properties acquired from Total Minatome are located principally in
the Gulf Coast, Rocky Mountains and Gulf of Mexico. Through this acquisition,
reserves increased by 75 Bcfe and natural gas/oil mix shifted at the time to
41%/59%. On January 31, 1997, Westport Oil and Gas consummated the Axem
transaction, an acquisition of oil and natural gas properties located in the
Rocky Mountains and the West Texas/Mid-Continent area, for a total purchase
price of $108.0 million. Through this acquisition, reserves increased nearly 86
Bcfe. Each of the noted acquisitions were accounted for using purchase
accounting and the results of the acquired properties were consolidated from the
respective closing dates. During 1995 and 1996, Westport Oil and Gas made
acquisitions totaling $82 million from Conoco, Chevron, Mobil, Koch and others
establishing its operations and reserve base in the Rocky Mountain and
Mid-Continent areas.

Results of operations are significantly impacted by the price of oil and
natural gas. During 1997, oil and natural gas prices were higher than what was
to be realized in 1998. However, since the second quarter of 1999, oil and
natural gas prices have increased steadily. The prices we receive for our oil
vary from NYMEX prices based on the location and quality of the crude oil. The
prices we receive for our natural gas are based on Henry Hub prices reduced by
transportation and processing fees.

Revenues are derived from the sale of oil and natural gas and natural gas
liquids. We utilize the sales method of accounting for natural gas sales,
whereby revenues are recognized based on cash received and not on our
proportionate share of production. We periodically enter into fixed price sales
agreements or other hedging transactions to take advantage of prices that we
believe to be attractive and to reduce risks related to potential price
declines. While our hedging contracts protect us from price declines related to
future production volumes that are hedged, such contracts can also reduce the
benefits we could realize from increases in oil and natural gas prices. Gains
and losses from hedging transactions are recognized as oil and natural gas
revenue when the associated production occurs.

Oil and natural gas production costs are composed of lease operating
expense and production taxes. Lease operating expense consists of pumpers'
salaries, utilities, maintenance and other costs necessary to
28
<PAGE> 32

operate our producing properties. In general, lease operating expense per unit
of production is lower on our offshore properties and does not fluctuate
proportionately with our production. Production taxes are assessed by applicable
taxing authorities as a percentage of revenues. However, properties located in
Federal waters offshore are generally not subject to production taxes. We expect
production taxes as a percentage of revenue to decline as we increase production
from our Gulf of Mexico properties.

Exploration expense consists of geological and geophysical costs, delay
rentals and the cost of unsuccessful exploratory wells. Delay rentals are
typically fixed in nature in the short term. However, other exploration costs
are generally discretionary and exploration activity levels are determined by a
number of factors, including oil and natural gas prices, availability of funds,
quantity and character of investment projects, availability of service providers
and competition.

Depletion of capitalized costs of producing oil and natural gas properties
is provided using the units-of-production method based upon proved reserves. For
purposes of computing depletion, proved reserves are redetermined as of the end
of each year and on an interim basis when deemed necessary. Because the economic
life of each producing well depends upon the assumed price for production,
fluctuations in oil and natural gas prices impact the level of proved reserves.
Higher prices generally have the effect of increasing reserves, which reduces
depletion, while lower prices generally have the effect of decreasing reserves,
which increases depletion.

We assess our proved properties on a field-by-field basis for impairment
whenever events or circumstances indicate that the capitalized costs of oil and
natural gas properties may not be recoverable. When making such assessments, we
compare the expected undiscounted future net revenues on a field-by-field basis
with the related net capitalized costs at the end of each period. When the net
capitalized costs exceed the undiscounted future net revenues, the cost of the
property is written down to "fair value," which is determined using the
discounted future net revenues on a field-by-field basis. In addition, we
periodically assess our unproved properties to determine if any such properties
have been impaired. Such assessment is based on, among other things, the fair
value of properties located in the same area as the unproved property, our
intent to pursue additional exploration opportunities on such property and
capital availability necessary to pursue such activity.

General and administrative expenses consist primarily of salaries and
related benefits, stock compensation expense, office rent, legal fees,
consultants, systems costs and other administrative costs incurred in our Denver
and Houston offices. While we expect such costs to increase with our growth, we
expect such increases to be proportionately smaller than our production growth.

RESULTS OF OPERATIONS

On April 7, 2000, Westport Oil and Gas merged with EPGC. This transaction
was effected by a merger between a newly-formed subsidiary of EPGC and Westport
Oil and Gas, resulting in Westport Oil and Gas becoming a wholly-owned
subsidiary of EPGC, which subsequently changed its name to Westport Resources
Corporation. As a result of the transaction, the stockholders of Westport Oil
and Gas became the majority stockholders of EPGC, and the senior management team
of Westport Oil and Gas became the management team for the combined company,
complemented by certain key managers from EPGC. The transaction was accounted
for using purchase accounting with Westport Oil and Gas as the surviving entity
and Westport Resources Corporation began consolidating the results of EPGC with
the results of Westport Oil and Gas as of the April 7, 2000 closing date. The
discussion below includes a comparison of the results of operations of Westport
Oil and Gas on a stand-alone basis for all periods presented, a comparison of
the revenues and lease operating expense of EPGC for all periods presented and a
presentation of pro forma revenues and expenses for the first quarter of 2000
and the year ended December 31, 1999, assuming the EPGC transaction was
consummated on January 1, 1999.

29
<PAGE> 33

Three Months Ended March 31, 2000 Compared to Three Months Ended March 31,
1999

REVENUES. Oil and natural gas revenues of Westport Oil and Gas for the
three months ended March 31, 2000 increased by $10.0 million, or 67%, from $15.0
million to $25.0 million. This increase resulted from increases of 160% and 46%
in realized oil and natural gas prices, respectively, partially offset by
decreases of 8% and 6% in oil and natural gas production volumes, respectively.
The decrease in production volumes from 8,690 Mmcfe to 8,090 Mmcfe was
attributable to sales of oil and natural gas properties in 1999 offset slightly
by wells shut in during the three months ended March 31, 1999 and returned to
production thereafter. Hedging transactions had the effect of reducing oil and
natural gas revenues by $3.6 million, or $0.44 per Mcfe, in the first quarter of
2000 and increasing oil and natural gas revenues by $0.7 million, or $0.08 per
Mcfe, in the first quarter of 1999. We have no hedges extending beyond 2000.

Oil and natural gas revenues of EPGC for the three months ended March 31,
2000 increased by $8.8 million, or 87%, from $10.1 million to $18.9 million.
This increase resulted from increases of 143% and 54% in realized oil and
natural gas prices, respectively and increases of 87% and 8% in oil and natural
gas production volumes, respectively, partially offset by a decrease in natural
gas liquids of 20 Mbbls or 36%. The increase in production volumes from 6,087
Mmcfe to 6,715 Mmcfe was attributable to new wells drilled at the West Cameron
180/198 complex and the South Marsh Island 39 field, which commenced production
subsequent to March 31, 1999.

On a pro forma basis, Westport's revenues and production volumes for the
quarter ended March 31, 2000 would have been $43.9 million and 14,805 Mmcfe,
respectively.

LEASE OPERATING EXPENSE. Lease operating expense of Westport Oil and Gas
for the three months ended March 31, 2000 increased by $1.0 million, or 18%,
from $5.6 million to $6.6 million. The increase in lease operating expense was
the result of additional well maintenance work performed during the three months
ended March 31, 2000 after the recovery of oil and natural gas prices in the
second half of 1999. On a per Mcfe basis, lease operating expense increased from
$0.65 to $0.82, primarily as a result of the additional well maintenance
discussed above.

Lease operating expense of EPGC for the three months ended March 31, 2000
decreased by $0.5 million, or 27%, from $1.7 million to $1.2 million. The
decrease in lease operating expense during the three months ended March 31, 2000
was the result of property sales in the fourth quarter of 1999. On a per Mcfe
basis, lease operating expense decreased from $0.27 to $0.18, primarily as a
result of sales of marginal producing properties.

On a pro forma basis, Westport's lease operating expense for the quarter
ended March 31, 2000 would have been $7.8 million, or $0.53 per Mcfe,
respectively.

PRODUCTION TAXES. Production taxes for the three months ended March 31,
2000 increased by $1.5 million, or 184%, from $0.8 million to $2.3 million. The
increase in production taxes is primarily attributable to an increase in the
average realized price of oil and natural gas. As a percent of oil and natural
gas revenues (excluding the effects of hedges), production taxes increased from
5.6% to 7.9%. The increase in production taxes as a percent of revenue is the
result of various states reducing tax rates in the first quarter of 1999 while
oil and natural gas prices were depressed, and subsequently reinstating the
original tax rates in 2000.

EXPLORATION COSTS. Exploration costs increased $0.9 million, or 80%, during
the three months ended March 31, 2000, from $1.0 million to $1.9 million. The
increase was primarily due to two unsuccessful exploratory wells drilled during
the three months ended March 31, 2000.

DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A) EXPENSE. DD&A expense
decreased $2.3 million, or 27%, during the three months ended March 31, 2000
from $8.5 million to $6.2 million. The average DD&A rate of $0.76 per Mcfe of
production during the 2000 quarter represents a 22% decrease from the $0.98 per
Mcfe recorded in the 1999 quarter. This decrease was attributable to an increase
in estimated proved reserves attributable to higher oil and natural gas prices
at March 31, 2000 as compared to March 31, 1999, as well as to proved property
impairments recorded in 1999.

30
<PAGE> 34

GENERAL AND ADMINISTRATIVE (G&A) EXPENSE. G&A expense increased $3.0
million, or 188%, during the three months ended March 31, 2000, from $1.6
million to $4.6 million. The increase was the result of compensation expense of
$3.4 million related to the repurchase of employee stock options recorded during
the three months ended March 31, 2000. Excluding that expense, G&A expense
decreased $0.4 million, or 27%, during the three months ended March 31, 2000. On
an Mcfe basis (excluding the effects of the stock option repurchase), G&A
expense decreased 22% from $0.18 during the 1999 quarter to $0.14 during the
2000 quarter.

OTHER INCOME (EXPENSE). Other income (expense) for the three months ended
March 31, 2000 was ($1.9 million) compared to $2.4 million for the three months
ended March 31, 1999. The variance was attributable to a $4.8 million gain on
the sale of assets recorded in the 1999 quarter, offset by a decrease in
interest expense of $0.5 million, resulting from a decrease in average
borrowings. Substantially all of the borrowings in both periods were under a
bank line of credit.

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

REVENUES. Oil and natural gas revenues of Westport Oil and Gas for 1999
increased by $22.3 million, or 43%, from $51.5 million to $73.8 million. This
increase resulted from increases of 52% and 23% in realized oil and natural gas
prices, respectively, and an increase of 64% in natural gas production volumes
partially offset by a decrease of 5% in oil production volumes. The increase in
production volumes from 28,999 Mmcfe to 33,113 Mmcfe was primarily attributable
to oil and natural gas properties acquired from Total Minatome Corporation in
October 1998. Hedging transactions had the effect of reducing oil and natural
gas revenues by $7.9 million, or $0.24 per Mcfe, in 1999 and increasing oil and
natural gas revenues by $0.3 million, or $0.01 per Mcfe, in 1998.

Oil and natural gas revenues of EPGC for 1999 increased by $19.1 million,
or 42%, from $45.8 million to $64.9 million. This increase resulted from
increases of 39% and 10% in realized oil and natural gas prices, respectively,
and increases of 20% and 23% in oil and natural gas production volumes,
respectively. The increase in production volumes from 22,496 Mmcfe to 27,666
Mmcfe was attributable to drilling activities at the West Cameron 180 and 198
fields and South Marsh Island 39 field.

On a pro forma basis, Westport's revenues and production volumes for 1999
would have been $138.7 million and 60,779 Mmcfe, respectively.

LEASE OPERATING EXPENSE. Lease operating expense of Westport Oil and Gas
for 1999 increased by $1.3 million, or 6%, from $21.6 million to $22.9 million.
The increase in lease operating expense was the result of additional expense
recorded as a result of oil and natural gas properties acquired from Total
Minatome Corporation in October 1998, offset by uneconomic properties shut in
during 1999 and sales of oil and natural gas properties during 1999. On a per
Mcfe basis, lease operating expense decreased from $0.74 in 1998 to $0.69 in
1999. The cost per Mcfe decreased because the acquired properties are primarily
natural gas properties, which have lower operating costs than oil properties.

Lease operating expense of EPGC for 1999 decreased by $2.8 million, or 28%,
from $10.0 million to $7.2 million. The decrease in lease operating expense was
the result of improvements in operating efficiencies. On a per Mcfe basis, lease
operating expense decreased from $0.45 in 1998 to $0.26 in 1999.

On a pro forma basis, Westport's lease operating expense for 1999 would
have been $30.1 million, or $0.50 per Mcfe.

PRODUCTION TAXES. Production taxes for 1999 increased by $1.8 million, or
48%, from $3.9 million to $5.7 million. The increase in production taxes is
primarily attributable to an increase in the average realized price of oil and
natural gas. As a percent of oil and natural gas revenues (excluding the effects
of hedges), production taxes remained relatively constant at 7.6% in 1998 and
7.0% in 1999.

EXPLORATION COSTS. Exploration costs decreased $7.4 million, or 50%, during
1999, from $14.7 million to $7.3 million. The decrease was primarily due to four
unsuccessful offshore exploratory wells and seven unsuccessful onshore
exploratory wells drilled during 1998 compared to one unsuccessful offshore
exploratory well and two unsuccessful onshore exploratory wells drilled during
1999.

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<PAGE> 35

DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A) EXPENSE. DD&A expense
decreased $11.1 million, or 30%, during 1999, from $36.3 million to $25.2
million. The average DD&A rate of $0.76 per Mcfe of production during 1999
represents a 39% decrease from the $1.25 per Mcfe recorded in 1998. This
decrease was attributable primarily to an increase in estimated proved reserves
attributable to higher oil and natural gas prices at December 31, 1999 as
compared to December 31, 1998, as well as to proved property impairments of $8.8
million recorded in 1998.

IMPAIRMENT OF PROVED PROPERTIES. During 1999 and 1998, Westport Oil and Gas
recognized proved property impairments of $3.1 million and $8.8 million,
respectively, in accordance with the provisions of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of."

IMPAIRMENT OF UNPROVED PROPERTIES. During 1999 and 1998, Westport Oil and
Gas recognized unproved property impairments of $2.3 million and $1.9 million,
respectively, as a result of an assessment of the exploration opportunities
existing on such properties.

GENERAL AND ADMINISTRATIVE (G&A) EXPENSE. G&A expense decreased $0.6
million, or 10%, during 1999, from $5.9 million to $5.3 million. The decrease
was the result of a reduction in workforce during 1999 combined with increased
overhead recoveries from development of our interest in the coalbed methane play
in the Powder River Basin. On a Mcfe basis, G&A expense decreased 20% from $0.20
during 1998 to $0.16 during 1999.

OTHER INCOME (EXPENSE). Other income (expense) for 1999 was ($5.1 million)
compared to ($7.9 million) for 1998. The variance was attributable to a $3.6
million gain on the sale of assets recorded in 1999. The gain was partially
offset by an increase in interest expense of $0.9 million, resulting from an
increase in average borrowings related to acquiring oil and natural gas
properties from Total Minatome Corporation in October 1998, and an increase in
interest rates in 1999. Substantially all of the borrowings in both periods were
under a bank line of credit.

Year Ended December 31, 1998 Compared to Year Ended December 31, 1997

REVENUES. Oil and natural gas revenues of Westport Oil and Gas for 1998
decreased by $11.6 million, or 18%, from $63.1 million to $51.5 million. This
decrease resulted from decreases of 38% and 2% in realized oil and natural gas
prices, respectively, offset partially by increases of 12% and 54% in oil and
natural gas production volumes. The increase in production volumes from 23,949
Mmcfe to 28,999 Mmcfe was attributable to the acquisition of properties from
Total Minatome Corporation in October 1998 and Axem in February 1997 and the
discovery of the Beaver Creek well in the Williston Basin in April 1998. Hedging
transactions had the effect of increasing oil and natural gas revenues by $0.3
million and $47,000 in 1998 and 1997, respectively.

Oil and natural gas revenues of EPGC for 1998 increased by $11.9 million,
or 35%, from $33.9 million to $45.8 million. This increase resulted from
increases of 73% and 77% in oil and natural gas production volumes partially
offset by decreases of 31% and 22% in realized oil and natural gas prices,
respectively. The increase in production volumes from 12,620 Mmcfe to 22,496
Mmcfe was primarily attributable to the acquisition of the West Cameron 180/198
complex in the fourth quarter in 1997. New wells drilled at West Cameron 540 in
mid-1998 also contributed to the production increase.

LEASE OPERATING EXPENSE. Lease operating expense of Westport Oil and Gas
for 1998 increased by $2.0 million, or 10%, from $19.6 million to $21.6 million.
The increase in lease operating expense was the result of additional operating
expenses incurred in connection with the properties acquired from Total Minatome
Corporation in October 1998. On a per Mcfe basis, lease operating expense
decreased from $0.82 to $0.74, primarily as a result of lower cost natural gas
properties acquired from Total Minatome Corporation.

Lease operating expense of EPGC for 1998 increased by $4.5 million, or 82%,
from $5.5 million to $10.0 million. The increase in lease operating expense was
the result of the acquisition of the West Cameron 180/198 complex in 1997. On a
per Mcfe basis, lease operating expense increased from $0.44 to $0.45.

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<PAGE> 36

PRODUCTION TAXES. Production taxes for 1998 decreased by $2.0 million, or
34%, from $5.9 million to $3.9 million. The decrease in production taxes is
primarily attributable to a decrease in the average realized price of oil and
natural gas. As a percent of oil and natural gas revenues (excluding the effects
of hedges), production taxes decreased from 9.4% to 7.6%. The decrease in
production taxes as a percent of revenue is the result of an increase in
production from properties in Federal waters offshore.

EXPLORATION COSTS. Exploration costs increased $7.3 million, or 98%, during
1998, from $7.4 million to $14.7 million. The increase was primarily due to four
unsuccessful offshore exploratory wells and seven unsuccessful onshore
exploratory wells drilled during 1998 compared to one unsuccessful offshore
exploratory well and three unsuccessful onshore exploratory wells drilled during
1997.

DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A) EXPENSE. DD&A expense
increased $12.6 million, or 53%, during 1998, from $23.7 million to $36.3
million. The increase was due to the increase in production as explained above
along with a decrease in estimated proved reserves. The average DD&A rate of
$1.25 per Mcfe of production during 1998 represents a 26% increase from the
$0.99 per Mcfe recorded in 1997. This increase was attributable primarily to a
decrease in estimated proved reserves as a result of lower oil and natural gas
prices at December 31, 1998 as compared to December 31, 1997.

IMPAIRMENT OF PROVED PROPERTIES. During 1998 and 1997, Westport Oil and Gas
recognized proved property impairments of $8.8 million and $5.8 million,
respectively, in accordance with the provisions of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of."

IMPAIRMENT OF UNPROVED PROPERTIES. During 1998 and 1997, Westport Oil and
Gas recognized unproved property impairments of $1.9 million and $0.4 million,
respectively, as a result of an assessment of the exploration opportunities
existing on such properties.

GENERAL AND ADMINISTRATIVE (G&A) EXPENSE. G&A expense increased $0.6
million, or 11%, during 1998, from $5.3 million to $5.9 million. The increase
was the result of an increase in workforce during 1998. On an Mcfe basis, G&A
expense decreased 9% from $0.22 during 1997 to $0.20 during 1998.

OTHER INCOME (EXPENSE). Other income (expense) for 1998 was ($7.9 million)
compared to ($5.4 million) for 1997. The variance was attributable to an
increase in interest expense of $2.7 million, resulting from an increase in
average borrowings during 1998. Substantially all of the borrowings in both
periods were under a bank line of credit.

LIQUIDITY AND CAPITAL RESOURCES

Principal uses of capital have been for the exploitation, acquisition and
exploration of oil and natural gas properties.

Cash flow from operating activities was $5.2 million for the three months
ended March 31, 2000 compared to $0.9 million for the three months ended March
31, 1999. The operating cash flow in the three month period increased compared
to the prior period due to the increase in commodity prices. Cash flow from
operating activities increased $14.6 million from $10.5 million for 1998 to
$25.1 million for 1999 due in part to a 14% increase in production and a 40%
increase in commodity prices.

Cash flow used in investing activities of $12.1 million for the three
months ended March 31, 2000 compared to cash flow generated from investing
activities of $23.3 million for the three months ended March 31, 1999. Cash flow
generated from investing activities of $14.2 million for 1999 compared to cash
flow used in investing activities of $115.9 million for 1998. Cash was generated
in 1999 due in part to $32.0 million of proceeds from sales of oil and natural
gas properties, which was offset by $17.8 million in additions to oil and
natural gas properties. Cash used in 1998 related to acquisitions and
exploitation and exploration activities.

Net cash used in financing activities was $0.3 million for the three months
ended March 31, 2000 compared to $14.3 million for the three months ended March
31, 1999. Cash flow used in financing activities of $29.9 million for 1999
compared to cash flow from financing activities of $104.7 million for 1998.
Financing activities have included primarily proceeds from the issuance of
common stock to Westport Energy LLC, proceeds from the issuance of long-term
debt and repayment of long-term debt.

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<PAGE> 37

Westport Oil and Gas entered into a credit agreement as of April 7, 2000
among a syndicate of banks led by Bank of America, N.A. in the aggregate amount
of $325.0 million. We are a guarantor to the credit agreement and thereby have
access to the funds available under the credit facility and are also subject to
the covenants set forth in the credit agreement. The amount available for
borrowing under the credit facility is limited to an initial borrowing base of
$200.0 million as of April 7, 2000, which will be redetermined semi-annually
beginning on October 1, 2000. The credit agreement matures on April 4, 2003.
Advances under the credit agreement can be in the form of either a base rate
loan or a Eurodollar loan. The interest on a base rate loan is a fluctuating
rate equal to (i) the higher of (a) the Federal funds rate plus 0.5% and (b)
Bank of America's prime rate, plus (ii) a margin of either 0% or 0.25% depending
on the amount outstanding under the credit agreement. The interest on a
Eurodollar loan is equal to the sum of (i) a margin of between 1.00% and 1.75%
depending on the amount outstanding under the credit agreement and (ii) the rate
obtained by dividing the Eurodollar rate by one minus the reserve requirement
for the Eurodollar loan.

The borrowings under the credit agreement as of May 31, 2000 were $155.5
million. Pro forma for application of our net proceeds from the offering to
repay indebtedness under the credit agreement, as of May 31, 2000, the
borrowings under the credit agreement would have been $ million and the
amount available for borrowings under the credit agreement would have been
$ million. In addition to various non-financial covenants, the credit
agreement contains two financial covenants; one that requires us to maintain a
current ratio of not less than 1.0 to 1.0 and another that requires us to
maintain a ratio of our EBITDA to our consolidated interest expense for the
period of four consecutive fiscal quarters, beginning with the fiscal quarter
ended March 31, 2000, of not less than 2.5 to 1.0. As of May 31, 2000, we were
in compliance with all credit agreement covenants. Any increases in these
interest rates can have an adverse impact on our results of operations and cash
flow. We use derivative financial instruments, specifically interest rate swaps,
to reduce and manage this risk. We have interest rate swap contracts for a
period commencing on July 30, 1998 and ending on March 11, 2002, for an
aggregate notional amount of $50 million with fixed interest rates between 5.58%
and 5.61% payable by us and the variable interest rate, a three-month LIBOR,
payable by the third party. The unrecognized gain on the interest rate swap
contracts totaled $720,000 based on December 31, 1999 market values. Based on
outstanding indebtedness at December 31, 1999 of $106.8 million, a change in
interest rates of 10% would affect future annual interest payments by
approximately $800,000. Based on the variable rate nature of the majority of the
debt, its fair value at December 31, 1999 approximated the carrying amount of
$106.8 million.

The capital expenditures for the year ended December 31, 1999 include $3.7
million for exploitation and $14.1 million for exploration. Our capital
expenditure budget for 2000 is $110 million, with approximately $75 million
allocated for exploitation and approximately $35 million allocated for
exploration. The exploration amounts include costs for 16-20 exploratory wells
in the Gulf of Mexico and three to six wells in the Rocky Mountains. The
exploitation costs are associated with continued exploitation of our existing
property base and amounts that are contingent upon drilling success. As of May
31, 2000, we have spent approximately $35 million of our capital expenditure
budget for the year. Actual levels of capital expenditures may vary
significantly due to a variety of factors, including:

- drilling results;

- product prices;

- industry conditions and outlook; and

- future acquisitions of properties.

We will continue to seek opportunities for acquisitions of proved reserves
with substantial exploitation and exploration potential. The size and timing of
capital requirements for acquisitions is inherently unpredictable. We expect to
fund these capital expenditure activities through a combination of cash flow
from operations, borrowings under our credit agreement.

We believe that our capital resources are adequate to meet the requirements
of our business. However, future cash flows are subject to a number of variables
including the level of production and oil and natural gas prices. We cannot
assure you that operations and other capital resources will provide cash

34
<PAGE> 38

in sufficient amounts to maintain planned levels of capital expenditures or that
increased capital expenditures will not be undertaken.

HEDGING TRANSACTIONS

We currently sell most of our oil and natural gas production under price
sensitive or market price contracts. To reduce our exposure to fluctuations in
oil and natural gas prices, we occasionally enter into hedging arrangements.
However, these contracts may also limit the benefits we would realize if prices
increase.

Through March 31, 2000, we had entered into the following hedging
arrangements covering the period beginning January 1, 2000. One Mmbtu
approximates one Mcf of natural gas.

<TABLE>
<CAPTION>
NATURAL GAS SWAPS OIL COLLARS
-------------------------- ---------------------------------------
AVERAGE
AVERAGE AVERAGE AVERAGE NYMEX
DAILY VOLUME NYMEX AVERAGE DAILY NYMEX FLOOR CEILING
TIME PERIOD (MMBTU) PRICE/MMBTU VOLUME (BBL) PRICE/BBL PRICE/BBL
----------- ------------ ----------- ------------- ----------- ---------
<S> <C> <C> <C> <C> <C>
1/1/00-12/31/00.................. 16,000 $2.52 2,000 $18.25 $20.62
7/1/00-12/31/00.................. -- -- 2,000 18.25 21.30
1/1/00-12/31/00.................. -- -- 1,000 20.50 24.30
</TABLE>

While it is not our intention to terminate any of the arrangements, we
estimate we would have had to pay approximately $10 million to terminate the
existing arrangements on March 31, 2000.

ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for all fiscal quarters of fiscal years beginning after June
15, 2000. We have not yet quantified the impacts of adopting SFAS No. 133 on our
financial statements and have not determined the timing of, or method of,
adoption of SFAS No. 133. However, SFAS No. 133 could increase volatility in
earnings.

In March 2000, the FASB issued Interpretation No. 44, "Accounting for
Certain Transactions involving Stock Compensation." The Interpretation clarifies
(a) the definition of employee for purposes of applying APB Opinion No. 25, (b)
the criteria for determining whether a plan qualifies as a noncompensatory plan,
(c) the accounting consequence of various modifications to the terms of
previously fixed stock options or awards, and (d) the accounting for an exchange
of stock options and/or awards in a business combination. The Interpretation is
effective July 1, 2000, but certain conclusions in the Interpretation cover
specific events that occur after either December 15, 1998, or January 12, 2000.
To the extent that the Interpretation covers events occurring during the period
after December 15, 1998, or January 12, 2000, but before the effective date of
July 1, 2000, the effects of applying the Interpretation will be recognized on a
prospective basis from July 1, 2000. Under provisions of the Interpretation, we
will be required to account for 714,257 of our outstanding stock options as
variable awards from July 1, 2000 until the date the options are exercised,
forfeited or expire unexercised. Compensation cost will be measured for the
amount of any increases in our stock price after July 1, 2000 and recognized
over the remaining vesting period of the options. Any decreases in our stock
price subsequent to July 1, 2000 will be recognized as a decrease in
compensation cost, limited to the amount of compensation cost previously
recognized as a result of increases in our stock price. Any adjustment to
compensation cost for further changes in the stock price after the award vests
will be recognized immediately.

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<PAGE> 39

BUSINESS AND PROPERTIES

ABOUT WESTPORT

OUR STRATEGY

- enhance our existing and acquired properties through exploitation to
enlarge our reserve base;

- pursue acquisitions with developmental upside to grow our inventory of
exploitation projects and to employ our operating expertise; and

- generate and drill an extensive prospect inventory in the Gulf of Mexico
by applying the latest available technology and leveraging off our
significant operational capabilities in that area.

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<PAGE> 40

We intend to implement our strategy as follows:

37
<PAGE> 41

$0.13 per Mcfe, respectively. We believe that our focus on a low cost structure
positions us to remain competitive in our exploitation, acquisition and
exploration activities.

WESTPORT OIL AND GAS TRANSACTION WITH EPGC

PROPERTIES -- PRINCIPAL AREAS OF OPERATIONS

Our operations are located in the Gulf of Mexico, the Rocky Mountains, West
Texas/Mid-Continent and the Gulf Coast. Set forth below is summary information
concerning average daily production during the first quarter of 2000 and wells,
reserves and PV10 value as of December 31, 1999 in our major areas of
operations.

<TABLE>
<CAPTION>
FIRST QUARTER
AVERAGE
NET DAILY NATURAL YEAR-END 1999
GAS EQUIVALENT --------------------------------------------------------------------------------
PRODUCTION PROVED RESERVE QUANTITIES PV10
----------------- NET ------------------------------------------ -----------------------
PRODUCING NATURAL NATURAL
MMCFE/D PERCENT WELLS CRUDE OIL GAS GAS LIQUIDS TOTAL AMOUNT PERCENT
------- ------- --------- --------- ------- ----------- ------ ------------- -------
(MMBBL) (BCF) (MMBBL) (BCFE) (IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gulf of Mexico........... 82.5 51% 27.4 5.7 128.5 0.6 166.1 $228.6 42%
Rocky Mountains.......... 54.1 33 319.8 22.6 50.9 0.0 186.7 210.2 38
West
Texas/Mid-Continent.... 12.4 8 355.4 6.4 12.5 0.0 51.0 63.5 12
Gulf Coast............... 13.7 8 32.4 1.8 39.8 0.0 50.7 42.1 8
----- --- ----- ---- ----- --- ----- ------ ---
Total............ 162.7 100% 735.0 36.5 231.7 0.6 454.5 $544.4 100%
===== === ===== ==== ===== === ===== ====== ===
</TABLE>

GULF OF MEXICO

The Gulf of Mexico represented 42% of our present value as of December 31,
1999 and contributed 51% of our first quarter 2000 production. We have interests
in 264,681 developed and 333,853 undeveloped gross acres in the Gulf of Mexico
and in 116 gross producing wells (approximately 27 net). The average net daily
production for the first quarter of 2000 was 83 Mmcfe. We had 166 Bcfe of proved
reserves in the Gulf of Mexico at December 31, 1999.

In addition to a solid production base with numerous exploitation
opportunities on our 65 developed blocks, the Gulf of Mexico provides us with
moderate-risk exploration targets. We currently own 67 undeveloped blocks in the
Gulf of Mexico and plan to drill 16 to 20 exploratory wells in 2000, while
maintaining a two to three year inventory of exploration projects. We have under
license, or access to license, 3-D seismic data covering over 10,000 square
miles (1,460 blocks) and 2-D seismic data covering 150,000 miles within the Gulf
of Mexico. We have had recent discoveries on 10 blocks, three of which are
producing and four of which we plan to put on production in the second half of
2000. We will continue exploitation on the remaining three blocks.

West Cameron 180/198. Our most valuable property in the Gulf of Mexico,
based upon PV10 value, is the West Cameron 180/198 complex, consisting of all or
a portion of seven offshore blocks including 30,000 gross developed and 5,000
gross undeveloped acres. This field had never been owned by an independent
producer prior to our purchase in October 1997. The complex is located 30 miles
offshore in 52 feet of water. It has produced approximately 1.7 Tcf of natural
gas and 10 Mmbbl of oil from over 20 separate producing zones since its
discovery. At the time that the complex was acquired, it was producing
approximately 30 Mmcfe/d net. Through the first half of 2000, we have drilled 16
wells and

38
<PAGE> 42

side-tracked an additional well, increasing the daily net production in the
first quarter of 2000 to 50 Mmcfe. As of December 31, 1999, we had 95 Bcfe of
proved reserves in the complex. As of March 31, 2000, we operated 15
wholly-owned producing wells and also had an interest in an additional four non-
operated gross wells.

Our geological and engineering field data, coupled with application of
modern seismic data and data processing, allow us to exploit these properties
and identify new, quality prospects within the complex. The highly faulted
nature of the complex provides opportunities for discovering additional
reserves. In the second half of 2000, an additional three to four development
wells are planned and three to four wells are planned for 2001. A number of
exploratory locations have also been identified, with one well planned for the
second half of 2000 and one to two wells likely to be drilled in 2001.

West Cameron 540. We purchased this exploration block in the March 1995
lease sale and drilled the discovery well in 1997. The field is located
approximately 110 miles offshore in 185 feet of water. We have working interests
in the field ranging from 50% to 100%. Currently, we operate four gross (2.5
net) wells with an average net daily production in the first quarter of 2000 of
15 Mmcfe. At December 31, 1999, we had 15 Bcfe of proved reserves in the field.
Additional potential exists for drilling one or two wells, based upon field
performance.

South Marsh Island 39. In May 1997, we discovered this field, which is
located approximately 60 miles offshore in 95 feet of water. We have a working
interest of 50%. Production is from multiple reservoirs ranging in depth from
8,200 feet to 13,600 feet. South Marsh Island 39 is on the flank of the same
salt dome as two analogous fields that had aggregate ultimate reserves of over
160 Bcfe (South Marsh Island 33 and South Marsh Island 38). We operate five
gross (2.5 net) wells with an average net daily production in the first quarter
of 2000 of 8 Mmcfe. At December 31, 1999, we had 16 Bcfe of proved reserves in
the field.

Additional potential in this field exists through recompletions of
shallower zones in producing wells, completing one shut-in well for gas cap
reserves, drilling additional wells in producing zones and deeper exploration.
One or two additional wells are anticipated for 2001.

Recent Discoveries

- South Timbalier 196. In 1999, we discovered this field, which is located
approximately 50 miles offshore in 105 feet of water. We operate the
field with a working interest of 50% and will install facilities and
commence production in the second half of 2000. We expect the gross
production will be 5 Mmcfe/d (approximately 2.0 Mmcfe/d net) from the
initial well. This field will produce from multiple reservoirs. Two
additional wells are planned for 2001.

- Vermilion 114. In 1998, we discovered this field, which is located 30
miles offshore in 50 feet of water. We operate the field with a working
interest of 50% and will install facilities and commence production in
the second half of 2000. We expect the gross production will be 5 Mmcfe/d
(approximately 2.1 Mmcfe/d net) from the initial well. This field will
produce from multiple reservoirs. Two additional wells are being
considered for 2001.

- West Cameron 613. In 1999, we discovered this field, which is located 130
miles offshore in 288 feet of water. We operate the field with a working
interest of 50% and will install the facilities and commence production
in the second half of 2000. We expect the gross production will be 15
Mmcfe/d (approximately 5.9 Mmcfe/d net) from the initial well. A second
exploration well will be drilled on the adjoining block in the second
half of 2000 and the potential for a third well is currently being
evaluated.

- High Island A-530. In 1999, this field was discovered, which is located
110 miles offshore in 190 feet of water. We have a 25% non-operated
working interest and will install the platform and facilities and
commence production in the second half of 2000. We expect the gross
production will be 5 Mmcfe/d (approximately 1.0 Mmcfe/d net).

39
<PAGE> 43

- Grand Isle 45. In early 2000, new reserves were discovered in this
existing field, which is located 25 miles offshore in 110 feet of water.
The well was drilled from an existing platform and began production in
May 2000. We have a 30% non-operated working interest in the well.
Initial daily gross production was 8 Mmcfe (approximately 1.9 Mmcfe/d
net).

- Vermillion 336. In the fourth quarter of 1999, we discovered this field,
which is located 90 miles offshore in 229 feet of water. We have a 20%
non-operated working interest. This well was drilled from an existing
platform and began production in December 1999. The average net daily
production for the first quarter of 2000 was 5 Mmcfe/d (approximately 1.2
Mmcfe/d net).

- West Cameron 172. In 2000, we discovered this reservoir within the West
Cameron 180/198 complex, which is located 30 miles offshore in 47 feet of
water. We have a 25% non-operated working interest. The well was drilled
from an existing platform and began production in May 2000. It is
currently producing at 5 Mmcfe/d (approximately 1.0 Mmcfe/d net).

- Grand Isle 103. In the first half of 2000, we discovered this field,
which is located 48 miles offshore in 260 feet of water. We have a
non-operated 21% working interest in the well. A second well is currently
being drilled and we plan to install facilities and commence production
in 2001.

- Vermilion 408. In 1999, we discovered this field, which is located
approximately 110 miles offshore in 390 feet of water. We have a 25%
non-operated working interest in the field. The discovery well tested at
18 Mmcfe/d (approximately 3.5 Mmcfe/d net). We will drill a second well
in this block in the second half of 2000. We anticipate installing
facilities in 2001 and commencing production in early 2002.

- Mississippi Canyon 773. In the fourth quarter of 1999, we discovered this
field, which is located 71 miles offshore in 5,554 feet of water. An
appraisal well was completed in the second quarter of 2000. We have an
approximately 4% non-operated working interest. We anticipate drilling an
additional appraisal well in fourth quarter of 2000 or first quarter of
2001 and anticipate beginning construction of the long lead-time
platform. Installation of facilities is anticipated in 2002 with
production commencing in late 2002 or early 2003. Additional development
drilling in 2002 and 2003 is also anticipated, depending on field size.

Other Exploration Activity. Through the first quarter of 2001, we
anticipate drilling the exploration prospects summarized in the following table:

<TABLE>
<CAPTION>
WORKING OPERATED/ WATER NET ESTIMATED
PROSPECT LOCATION INTEREST NON-OPERATED DEPTH WELL COSTS
----------------- -------- ------------ ------ -------------
(%) (FEET) (MILLIONS)
<S> <C> <C> <C> <C>
East Cameron 104............................... 60 Operated 59 $1.4
Eugene Island 44............................... 60 Operated 19 1.9
Eugene Island 45............................... 60 Operated 19 1.4
Mississippi Canyon 322/366..................... 35 Non-operated 774 3.0
Mississippi Canyon 489/490..................... 30 Non-operated 1,899 1.7
Ship Shoal 86.................................. 40 Non-operated 19 1.2
South Marsh Island 50.......................... 50(1) Operated 104 1.5
South Timbalier 267............................ 50(1) Operated 216 1.7
Vermilion 236.................................. 50 Non-operated 147 1.0
West Cameron 370............................... 60 Operated 72 1.4
</TABLE>

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

(1) Assumes the sale of partial interest from our current 100% working interest.

ROCKY MOUNTAINS

The Rocky Mountain region represented 38% of our present value as of
December 31, 1999 and contributed 33% of our first quarter 2000 production. We
have interests in 468,958 developed and 122,682 undeveloped gross acres in the
region and in 1,351 gross producing wells (approximately 320 net).

40
<PAGE> 44

The average daily net production in the first quarter of 2000 was 54 Mmcfe. We
had 187 Bcfe of proved reserves in the Rocky Mountain region at December 31,
1999.

The majority of the present value of our Rocky Mountain region reserves is
concentrated in the Williston Basin of North Dakota and the Powder River and Big
Horn basins and the Greater Green River area of Wyoming. Our Rocky Mountain
region strategy is to develop lower-risk opportunities, exploit our infill,
horizontal and secondary/tertiary recovery opportunities, and make tactical
acquisitions to enhance current operations.

North Dakota. We have interests in 95,510 developed and 86,487 undeveloped
gross acres in North Dakota and in 275 gross producing wells (approximately 147
net). We operate 224 of these gross wells. The average net daily production in
the first quarter of 2000 was 24 Mmcfe. We had 72 Bcfe of proved reserves at
December 31, 1999. Based on gross, operated production we are the state's fourth
largest oil producer.

Our three most significant projects in North Dakota are the South Fryburg
Tyler area, the Wiley field and the Horse Creek Unit. All of these projects are
in the Williston basin.

- South Fryburg Tyler Area. We operate a 21 gross (approximately 10 net)
well unit where we recently completed a well with an initial daily rate
in excess of 400 bbl/d (approximately 200 bbl/d net). We also own 9 gross
(approximately 5 net) wells producing from a deeper reservoir and 22,391
gross undeveloped acres adjacent to the unit. This acreage is held for
deeper, horizontal drilling potential and we plan to drill four
horizontal wells in 2000, one of which has been completed and is
producing in excess of 200 bbl/d. We had 1.8 Mmbbl (11 Bcfe) of proved
reserves in this area at December 31, 1999.

- Wiley Field. We operate this waterflood with 74 gross producing wells
(approximately 40 net). We unitized the field in 1997. In 1999 and the
first half of 2000, we converted four producing wells to injector wells
and drilled two horizontal wells. One of these wells initially produced
over 400 bbl/d (approximately 180 bbl/d net). Two additional horizontal
wells are planned for the second half of 2000, with further development
planned in 2001 from an inventory of 24 horizontal locations.

- Horse Creek Unit. We own and operate this secondary recovery unit
comprising 14 gross producing (approximately 4 net) wells. We utilize
high pressure air injection as the secondary recovery method. Unit
production has increased by nearly 70% since air injection was initiated
in 1997. We believe that further production increases will be realized as
additional wells respond to the injection. We are one of three operators
in the Rocky Mountains applying this technology and believe that it has a
broader application within the region. We intend to apply the experience
gained from this project in evaluating potential acquisition candidates
where this technology could be employed.

Wyoming. We have an interest in 244,970 developed and 28,759 undeveloped
gross acres in the region and in 478 gross producing wells (approximately 158
net). We operate 165 of these gross wells. The average daily net production in
the first quarter of 2000 was 27 Mmcfe. We had 108 Bcfe of proved reserves in
this area at December 31, 1999. Our three primary areas of focus in Wyoming are
the Big Horn basin, the Powder River basin and the Greater Green River area.

- Big Horn Basin. We had 30 Bcfe of proved reserves in this basin at
December 31, 1999. Our most valuable onshore property based on PV10 value
is the Gooseberry field. We own a 100% working interest (nearly 90% net
revenue interest) in this 23 well, operated field, which consists of two
waterflood units. Since acquiring the field in 1995, we have increased
production by nearly 70% through the acquisition of proprietary 3-D
seismic, drilling of delineation wells, installation of the two
waterfloods and the addition of shallower producing zones. We believe
that the shallower producing zone also has potential for waterflooding.

- Powder River Basin. We have an interest in 173,832 developed and 14,769
undeveloped gross acres in this basin and in 394 gross producing wells
(approximately 119 net). We had 54 Bcfe of proved reserves in this basin
at December 31, 1999. In 2000, we plan to continue our coalbed methane

41
<PAGE> 45

drilling in the Bonepile area and initiate an alkaline surfactant polymer
(ASP) flood in our Mellott Ranch field.

Our recent activity in the Powder River basin has emphasized coalbed
methane drilling. As a result of past acquisitions, we own more than
30,000 net acres in this play. Based upon expected spacing regulations,
more than 400 coalbed methane wells could ultimately be drilled on our
acreage. All of our drilling to date has been in the Bonepile area south
of Gillette, Wyoming. In this area, the extensive Wyodak coal averages 75
feet in thickness at a depth of approximately 700 feet. Drilling,
completion and facility costs in this area are attractive, with the
average well costing less than $80,000. Since 1999, we have drilled 69
wells and gross production on May 31, 2000 was nearly 14 Mmcf/d
(approximately 5 Mmcf/d net) of gas from 42 wells, for an average of 330
Mcf per well. Production from the remaining wells will commence upon
completion of additional gathering lines and facilities in the second half
of 2000. We have permits on and plan to drill an additional 25 wells in
the second half of 2000. The Bonepile leasehold of 2,545 net acres
represents 8.3% of our land position in the coalbed methane fairway.

Our plan to install an ASP flood in our 100% owned and operated Mellott
Ranch field is based on two analogous fields where ASP floods have been
successfully implemented. In the nearby Kiehl West field, the ASP flood
was initiated in 1987 and the field has recovered nearly 900,000
additional barrels of oil. In the nearby Cambridge field, the flood is
projected to recover nearly 2.5 million additional barrels of oil. Based
on field size and modeling of reservoir characteristics, we believe that
we can achieve recoveries similar to the Cambridge field.

- Greater Green River Area. We have interests in 61 gross producing wells
(approximately 16 net). We operate 20 of these gross wells. We had 24
Bcfe of proved reserves in this area at December 31, 1999. Exploitation
of southwest Wyoming gas fields continues through infill development,
recompletion and reworking of old wells in addition to the application of
improved fracture stimulation technology. Through May 31, 2000, we have
participated in the drilling of 4 wells (3 successful) and anticipate
drilling 6 more wells in the Greater Green River area in the second half
of 2000. Further, we plan to increase production in two wells utilizing
current fracturing technology.

WEST TEXAS/MID-CONTINENT

The West Texas/Mid-Continent area represented 12% of our present value as
of December 31, 1999 and contributed 8% of our first quarter 2000 production. We
have an interest in 61,205 developed and 77,553 undeveloped gross acres and in
1,346 gross producing wells (approximately 355 net). The average net daily
production in the first quarter of 2000 was 12 Mmcfe. We had 51 Bcfe of proved
reserves in this area at December 31, 1999. Our West Texas/Mid-Continent region
consists primarily of properties in Texas, Oklahoma and Kansas, with reserves
concentrated in the Permian and Anadarko basins.

Texas. We own interests in 1,238 gross producing wells (approximately 300
net). We had 33 Bcfe (5.5 Mmboe) of proved reserves in this area at December 31,
1999. We continue to exploit our 100% working interest ownership in the Howard
Glasscock field, which is our most valuable asset in the region based on PV10
value. Based on the results from adjacent successful waterfloods, we believe
that additional potential exists through the expansion and installation of
waterfloods on our leases. In 1999, we installed a waterflood on one of our
leases and expect response in 2001. In the first quarter of 2000, we drilled six
infill injection wells. For the remainder of 2000, we plan to continue our
waterflood development by installing injection capacity in conjunction with an
offset operator.

Oklahoma and Kansas. We own interests in 108 gross producing wells
(approximately 56 net). We had over 18 Bcfe of proved reserves in this area at
December 31, 1999. Our principal properties in Oklahoma and Kansas are all
operated and include the 27-well East Harmon Waterflood Unit in Oklahoma, a
15-well waterflood in Oklahoma and a 19-well secondary recovery project in
Kansas.

42
<PAGE> 46

GULF COAST

The Gulf Coast represented 8% of our present value as of December 31, 1999
and contributed 8% of our first quarter 2000 production. We have interests in
75,491 developed and 15,558 undeveloped gross acres in the Gulf Coast and in 336
gross producing wells (approximately 32 net). The average net daily production
in the first quarter of 2000 was 14 Mmcfe. We had 51 Bcfe of proved reserves in
the Gulf Coast at December 31, 1999.

Our activity in the Gulf Coast is focused on a multi-year drilling program
in Northern Louisiana. We acquired this interest in late 1998 and have
identified 110 development locations in our four fields -- Ada, Sibley, West
Bryceland and Sailes. The 2,000 foot thick Hosston interval contains over 20
separate producing zones. Gross reserves per well average approximately 3 Bcf.
Through 1999 we drilled 21 wells, all of which were successful. In 2000, we plan
to drill 34 wells, of which 13 had been drilled (11 successful) by May 31, 2000.
Bypassed producing zones are being completed in 40 existing wells. We anticipate
a similar activity level for drilling in each of the next three years.

PROVED RESERVES

The following table sets forth estimated year end proved reserves for the
periods indicated:

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
------------------------------ ---------
AS OF DECEMBER 31,
------------------------------------------
1997 1998 1999 1999
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
OIL (MBBLS)
Developed........................................ 25,588 20,323 29,489 31,453
Undeveloped...................................... 2,403 4,053 3,261 5,054
-------- -------- -------- --------
Total.................................... 27,991 24,376 32,750 36,507
======== ======== ======== ========
NATURAL GAS (MMCF)
Developed........................................ 26,651 80,328 82,638 174,583
Undeveloped...................................... 1,925 19,957 36,531 57,136
-------- -------- -------- --------
Total.................................... 28,576 100,285 119,169 231,719
======== ======== ======== ========
NATURAL GAS LIQUIDS (MBBLS)
Developed........................................ 36 50 28 486
Undeveloped...................................... 0 0 0 144
-------- -------- -------- --------
Total.................................... 36 50 28 630
======== ======== ======== ========
TOTAL (MMCFE)...................................... 196,737 246,840 315,838 454,542
======== ======== ======== ========
PRESENT VALUE ($ IN THOUSANDS)
Developed........................................ $146,985 $101,574 $300,328 $460,116
Undeveloped...................................... 8,423 9,710 48,771 84,266
-------- -------- -------- --------
Total.................................... $155,408 $111,284 $349,099 $544,382
======== ======== ======== ========
</TABLE>

Estimated quantities of oil and natural gas reserves and the present value
thereof are based upon reserve reports prepared by the independent petroleum
engineering firms of Ryder Scott Company L.P. and Netherland, Sewell &
Associates, Inc.

Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required to establish production.

43
<PAGE> 47

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
exploitation expenditures. The data in the above tables represent estimates
only. Oil and natural gas reserve engineering is inherently a subjective process
of estimating underground accumulations of oil and natural gas that cannot be
measured exactly, and estimates of other engineers might differ materially from
those shown above. The accuracy of any reserve estimate is a function of the
quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may justify revisions. Accordingly, reserve estimates may vary from the
quantities of oil and natural gas that are ultimately recovered.

Future prices received for production and costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of these
estimates. The present value shown should not be construed as the current market
value of the reserves. The 10% discount factor used to calculate present value,
which is mandated by the SEC, is not necessarily the most appropriate discount
rate. The present value, no matter what discount rate is used, is materially
affected by assumptions as to timing of future production, which may prove to be
inaccurate. For properties that we operate, expenses exclude our share of
overhead charges. In addition, the calculation of estimated future net revenues
does not take into account the effect of various cash outlays, including, among
other things, general and administrative costs and interest expense.

PRODUCTION AND PRICE HISTORY

The following table sets forth information regarding net production of oil,
natural gas and natural gas liquids, and certain price and cost information for
each of the periods indicated:

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
--------------------------------------------- ------------------------
THREE
THREE MONTHS MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31, YEAR ENDED ENDED
--------------------------- --------------- DECEMBER 31, MARCH 31,
1997 1998 1999 1999 2000 1999 2000
------- ------- ------- ------ ------ ------------ ---------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (Mbbls).............. 3,114 3,483 3,300 859 794 3,893 901
Natural gas (Mmcf)....... 5,265 8,101 13,313 3,536 3,326 36,420 9,181
NGL (Mbbls)(1)........... -- -- -- -- -- 167 36
Total Mmcfe.............. 23,949 28,999 33,113 8,690 8,090 60,779 14,805
AVERAGE PRICES(2):
Oil (per bbl)............ $ 17.35 $ 10.79 $ 16.45 $10.14 $26.36 $ 16.69 $ 26.38
Natural gas (per Mcf).... 1.71 1.68 2.06 1.58 2.30 2.19 2.49
NGL (per bbl)(1)......... -- -- -- -- -- 11.22 23.10
Total per Mcfe........... 2.63 1.77 2.47 1.64 3.53 2.41 3.21
AVERAGE COSTS (PER MCFE):
Lease operating
expense................ $ 0.82 $ 0.74 $ 0.69 $ 0.65 $ 0.82 $ 0.50 $ 0.53
General and
administrative......... 0.22 0.20 0.16 0.18 0.14(3) 0.13 0.13(3)
Depletion, depreciation
and amortization....... 0.99 1.25 0.76 0.98 0.76 0.96 1.10
</TABLE>

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

(1) Production of natural gas liquids was not meaningful for historical periods.

(2) Does not include the effects of hedging transactions.

(3) Does not include the effects of compensation expense of $3.4 million
recorded as a result of repurchase of employee stock options in March 2000
in connection with the transaction between Westport Oil and Gas and EPGC.

44
<PAGE> 48

PRODUCING WELLS

The following table sets forth information at December 31, 1999 relating to
the producing wells in which we owned a working interest as of that date. We
also held royalty interests in 1,654 producing wells as of that date. Wells are
classified as oil or natural gas wells according to their predominant production
stream.

<TABLE>
<CAPTION>
AVERAGE
GROSS NET WORKING
WELLS WELLS INTEREST(1)
----- ----- -----------
<S> <C> <C> <C>
Crude oil and liquids..................................... 2,033 614.6 30.2%
Natural gas............................................... 1,116 120.4 10.8
----- -----
Total..................................................... 3,149 735.0
===== =====
</TABLE>

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

(1) Our weighted average working interest is 23.3%.

ACREAGE

The following table sets forth information at December 31, 1999 relating to
acreage held by us. Developed acreage is assigned to producing wells.
Undeveloped acreage is acreage held under lease, permit, contract or option that
is not in a spacing unit for a producing well, including leasehold interests
identified for exploitation or exploratory drilling.

<TABLE>
<CAPTION>
GROSS NET
ACREAGE ACREAGE
--------- -------
<S> <C> <C>
DEVELOPED:
Gulf of Mexico............................................ 264,681 65,442
Rocky Mountain............................................ 468,958 168,509
Mid-Continent............................................. 61,205 23,766
Gulf Coast................................................ 75,491 8,878
--------- -------
Total Developed........................................... 870,335 266,595
UNDEVELOPED:
Gulf of Mexico............................................ 333,853 160,684
Rocky Mountain............................................ 122,682 68,001
Mid-Continent............................................. 77,553 29,478
Gulf Coast................................................ 15,558 2,624
--------- -------
Total Undeveloped......................................... 549,646 260,787
--------- -------
Total............................................. 1,419,981 527,382
========= =======
</TABLE>

45
<PAGE> 49

DRILLING RESULTS

The following table sets forth information with respect to wells drilled
during the periods indicated. The information should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled,
quantities of reserves found or economic value. Productive wells are those that
produce commercial quantities of hydrocarbons, whether or not they produce a
reasonable rate of return.

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
---------------------- -----------
YEAR ENDED DECEMBER 31,
------------------------------------
1997 1998 1999 1999
---- ---- ---- -----------
<S> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Productive
Gross............................................... 42 61 83 88
Net................................................. 17.7 14.5 28.2 33.2
Dry
Gross............................................... 3 1 0 0
Net................................................. 2.5 0.6 0 0
EXPLORATORY WELLS:
Productive
Gross............................................... 9 5 8 13
Net................................................. 3.9 1.9 1.4 3.6
Dry
Gross............................................... 7 8 3 3
Net................................................. 3.4 1.8 1.3 1.3
</TABLE>

During the first quarter of 2000, we spudded 47 wells, of which 43 gross
(15.85 net) wells had been completed as productive, two gross (1.28 net) wells
had been plugged and abandoned and two wells were in progress, consisting of 1
gross development well (0.996 net) and 1 gross exploratory well (0.40 net).

PURCHASERS AND MARKETING

Our oil and natural gas production is principally sold to end users,
marketers and other purchasers having access to nearby pipeline facilities. In
areas where there is no practical access to pipelines, oil is trucked to storage
facilities. Our marketing of oil and natural gas can be affected by factors
beyond our control, the effects of which cannot be accurately predicted. For
fiscal year 1999, our largest purchasers included Conoco, Inc., Energen
Resources MAQ, Inc. and EOTT Energy Corporation, which accounted for 26%, 20%,
and 20% of oil and natural gas sales, respectively. We do not believe, however,
that the loss of any of our purchasers would have a material adverse effect on
our operations. On a pro forma basis for fiscal year 1999, these three
purchasers would have accounted for 14%, 11% and 11%, respectively, whereas
Dynegy Inc. and Equitable Energy, LLC would have accounted for 26% and 18%,
respectively. The sales to Equitable Energy, LLC were terminated in mid-2000.

COMPETITION

We compete with major and independent oil and natural gas companies. Some
of our competitors have substantially greater financial and other resources than
we do. In addition, larger competitors may be able to absorb the burden of any
changes in Federal, state and local laws and regulations more easily than we
can, which would adversely affect our competitive position. Our competitors may
be able to pay more for exploratory prospects and productive oil and natural gas
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than we can. Further, these companies may
enjoy technological advantages and may be able to implement new technologies
more rapidly than we can. Our ability to explore for oil and natural gas
prospects and to acquire additional properties in the

46
<PAGE> 50

future will depend upon our ability to conduct operations, to evaluate and
select suitable properties, implement advanced technologies and to consummate
transactions in this highly competitive environment.

REGULATION

FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL
GAS. Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by
the Federal Energy Regulatory Commission. In the past, the Federal government
has regulated the prices at which natural gas could be sold. Deregulation of
natural gas sales by producers began with the enactment of the Natural Gas
Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act,
which removed all remaining Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting producer sales of natural gas effective January 1,
1993. Congress could, however, reenact price controls in the future.

Our sales of natural gas are affected by the availability, terms and cost
of pipeline transportation. The price and terms for access to pipeline
transportation remain subject to extensive Federal regulation. Commencing in
April 1992, the Federal Energy Regulatory Commission issued Order No. 636 and a
series of related orders, which required interstate pipelines to provide
open-access transportation on a basis that is equal for all natural gas
suppliers. The Federal Energy Regulatory Commission has stated that it intends
for Order No. 636 to foster increased competition within all phases of the
natural gas industry. Although Order No. 636 does not directly regulate our
production and marketing activities, it does affect how buyers and sellers gain
access to the necessary transportation facilities and how we and our competitors
sell natural gas in the marketplace. The courts have largely affirmed the
significant features of Order No. 636 and the numerous related orders pertaining
to individual pipelines, although some appeals remain pending and the Federal
Energy Regulatory Commission continues to review and modify its regulations
regarding the transportation of natural gas. For example, the Federal Energy
Regulatory Commission has recently begun a broad review of its transportation
regulations, including how its regulations operate in conjunction with state
proposals for retail natural gas marketing restructuring, whether to eliminate
cost-of-service based rates for short-term transportation, whether to allocate
all short-term capacity on the basis of competitive auctions, and whether
changes to its long-term transportation service policies may be appropriate to
avoid a market bias toward short-term contracts. We cannot predict what action
the Federal Energy Regulatory Commission will take on these matters, nor can we
accurately predict whether the Federal Energy Regulatory Commission's actions
will achieve the goal of increasing competition in markets in which our natural
gas is sold. However, we do not believe that any action taken will affect us in
a way that materially differs from the way it affects other natural gas
producers, gatherers and marketers.

The Outer Continental Shelf Lands Act requires that all pipelines operating
on or across the Outer Continental Shelf provide open-access, non-discriminatory
service. Although the Federal Energy Regulatory Commission has opted not to
impose the regulations of Order No. 509, in which the Federal Energy Regulatory
Commission implemented the Outer Continental Shelf Lands Act, on gatherers and
other non-jurisdictional entities, the Federal Energy Regulatory Commission has
retained the authority to exercise jurisdiction over those entities if necessary
to permit non-discriminatory access to service on the Outer Continental Shelf.

Commencing in May 1994, the Federal Energy Regulatory Commission issued a
series of orders that, among other matters, 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 Federal Energy Regulatory Commission's transportation
policies, it does not have pervasive jurisdiction over natural gas gathering
facilities and services, and that such facilities and services located in state
jurisdictions are most properly regulated by state authorities. This Federal
Energy Regulatory Commission action may further encourage regulatory scrutiny of
natural gas gathering by state agencies. We do not believe that we will be
affected by the Federal Energy Regulatory Commission's new gathering policy any
differently than other natural gas producers, gatherers and marketers.

47
<PAGE> 51

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
and the courts. 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 Federal Energy Regulatory Commission and
Congress will continue.

FEDERAL LEASES. A substantial portion of our operations are located on
Federal oil and natural gas leases, which are administered by the Minerals
Management Service. Such leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed Minerals
Management Service regulations and orders pursuant to the Outer Continental
Shelf Lands Act (which are subject to interpretation and change by the Minerals
Management Service). For offshore operations, lessees must obtain Minerals
Management Service approval for exploration plans and exploitation 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 Minerals Management Service prior to the commencement of drilling. The
Minerals Management Service has promulgated regulations requiring offshore
production facilities located on the Outer Continental Shelf to meet stringent
engineering and construction specifications. The Minerals Management Service
also has regulations restricting the flaring or venting of natural gas, and has
proposed to amend such regulations to prohibit the flaring of liquid
hydrocarbons and oil without prior authorization. Similarly, the Minerals
Management Service has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the installation and removal of all
production facilities. To cover the various obligations of lessees on the Outer
Continental Shelf, the Minerals Management Service generally requires that
lessees have substantial net worth or post bonds or other acceptable assurances
that such obligations will be met. The cost of these bonds or other surety can
be substantial, and there is no assurance that bonds or other surety can be
obtained in all cases. Under some circumstances, the Minerals Management Service
may require any of our operations on Federal leases to be suspended or
terminated. Any such suspension or termination could materially adversely affect
our financial condition and results of operations.

The Minerals Management Service has recently issued a notice of proposed
rulemaking in which it proposes to amend its regulations governing the
calculation of royalties and the valuation of crude oil produced from Federal
leases. This proposed rule would modify the valuation procedures for both arm's-
length and non-arm's-length crude oil transactions, establish a new form for
collecting value differential data, and amend the valuation procedure for the
sale of Federal royalty oil. We cannot predict what action the Minerals
Management Service will take on this matter. We believe that these rules, if
adopted as proposed, will not have a material impact on our financial condition,
liquidity or results of operations.

STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION. We own interests in
properties located in the Louisiana state waters of the Gulf of Mexico.
Louisiana regulates drilling and operating activities by requiring, among other
things, drilling permits and bonds and reports concerning operations. The laws
of Louisiana also govern a number of environmental and conservation matters,
including the handling and disposing of waste materials, unitization and pooling
of oil and natural gas properties and establishment of maximum rates of
production from oil and natural gas wells.

OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and natural gas liquids by us are not currently regulated and are made at market
prices. Effective as of January 1, 1995, the Federal Energy Regulatory
Commission implemented regulations establishing an indexing system for
transportation rates for oil that could increase the cost of transporting oil to
the purchaser. We do not believe that these regulations affect us any
differently than other natural gas producers, gatherers and marketers.

ENVIRONMENTAL REGULATIONS. Our operations, which include the bulk storage
of oil and other hazardous materials, are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection, including those listed below. We
could incur substantial costs, including cleanup costs, fines and civil or
criminal sanctions, as a result of violations of or liabilities under
environmental laws or the non-compliance with environmental permits

48
<PAGE> 52

required at our facilities. Public interest in the protection of the environment
has increased dramatically in recent years. Offshore drilling in some areas has
been opposed by environmental groups and, in some areas, has been restricted. To
the extent laws are enacted or other governmental action is taken that prohibits
or restricts drilling or otherwise imposes environmental protection requirements
that result in increased costs to the oil and natural gas industry, our business
and prospects could be adversely affected.

Under the Comprehensive Environmental Response, Compensation, and Liability
Act, also known as the "Superfund" law, as well as similar state statutes, an
owner or operator of real property or a person who arranges for disposal of
hazardous substances may be liable for the costs of removing or remediating
hazardous substance contamination. Liability may be imposed on a current owner
or operator without regard to fault and for the entire cost of the cleanup. It
is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. However, we are not aware of any
current claims under the Superfund law or similar state statutes against us.

The Oil Pollution Act of 1990 and regulations thereunder impose liability
on "responsible parties," including the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located, for oil removal costs and resulting public and private damages relating
to oil spills in United States waters. While liability limits apply in some
circumstances, a party cannot take advantage of liability limits if the spill
was caused by gross negligence or willful misconduct or resulted from violation
of a Federal safety, construction or operating regulation, or if the party fails
to report a spill or to cooperate fully in the cleanup. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75 million in other damages. The Oil Pollution
Act also requires a responsible party to submit proof of its financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill and to prepare oil spill contingency
plans. We believe we are in compliance with these requirements.

We conduct remedial activities at some of our onshore facilities as a
result of spills of oil or produced saltwater from current or historical
activities. To date, the cost of such activities have not been material.
However, we could incur significant cost at these or other sites if additional
contaminants are detected or clean-up obligations imposed.

Our operations are also subject to the regulation of air emissions under
the Clean Air Act, comparable state and local requirements and the Outer
Continental Shelf Lands Act and of water discharges under the Clean Water Act.
We may be required to incur capital expenditures to upgrade pollution control
equipment or become liable for non-compliance with applicable permits.

In addition, legislation has been proposed in Congress from time to time
that would reclassify some oil and natural gas exploration and production wastes
as "hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. This, or the
imposition of other environmental legislation, could increase our operating or
compliance costs.

We believe that we are in compliance in all material respects with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on us.

OPERATING HAZARDS AND INSURANCE

The oil and natural gas business involves a variety of operating risks,
including fires, explosions, blowouts, environmental hazards and other potential
events which can adversely affect our operations. In addition, our offshore
operations also are subject to a variety of operating risks peculiar to the
marine environment, such as capsizing, collisions, and damage or loss from
hurricanes or other adverse weather conditions, any of which can cause
substantial damage to facilities. Any of these problems could adversely affect
our ability to conduct operations and cause us to incur substantial losses. Such
losses could reduce or eliminate the funds available for exploration,
exploitation or leasehold acquisitions, or result in loss of properties.

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<PAGE> 53

In accordance with industry practice, we maintain insurance against some,
but not all, potential risks and losses. We do not carry business interruption
insurance. For some risks, we may not obtain insurance if we believe the cost of
available insurance is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable at a
reasonable cost. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect us.

EMPLOYEES

At May 31, 2000, we had 93 full-time employees and seven consultants. We
believe that our relationships with our employees are satisfactory. None of our
employees are covered by a collective bargaining agreement. From time to time,
we use the services of independent consultants and contractors to perform
various professional services, particularly in the areas of construction,
design, well-site surveillance, permitting and environmental assessment.
Independent contractors often perform field and on-site production operation
services for us, including pumping, maintenance, dispatching, inspection and
testing.

LEGAL PROCEEDINGS

From time to time, we may be a party to various legal proceedings. We are
not currently party to any material pending legal proceedings.

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<PAGE> 54

MANAGEMENT

EXECUTIVE OFFICERS AND DIRECTORS

The following table sets forth the names, ages and positions of our
executive officers and directors as of June 15, 2000.

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Donald D. Wolf................... 57 Chairman, Chief Executive Officer and
Director
Barth E. Whitham................. 43 President, Chief Operating Officer and
Secretary
James H. Shonsey................. 48 Chief Financial Officer
Kenneth D. Anderson.............. 57 Vice President -- Accounting
Andrew M. Ashby.................. 45 Vice President -- Operations Denver
Division
Lynn S. Belcher.................. 47 Vice President -- Business Development
Brian K. Bess.................... 39 Vice President -- Engineering
Klein P. Kleinpeter.............. 48 Vice President and General Manager, Gulf
Coast
Michael Russell.................. 50 Director
Murry S. Gerber.................. 47 Director
David L. Porges.................. 42 Director
James M. Funk.................... 50 Director
Alex M. Cranberg................. 45 Director
William F. Wallace............... 60 Director
</TABLE>

The following biographies describe the business experience of our executive
officers and directors.

Donald D. Wolf, Chairman, Chief Executive Officer and Director since April
2000. He joined Westport Oil and Gas in June 1996 as chairman and chief
executive officer and has a diversified 35-year career in the oil and natural
gas industry. In 1981, Mr. Wolf founded General Atlantic Energy Co., where he
was chairman and chief executive officer when it successfully completed an
initial public offering in 1993. General Atlantic subsequently merged with UMC
Petroleum in 1994. Mr. Wolf resigned from UMC in May 1996 as president and chief
operating officer. Prior to that time, Mr. Wolf held positions with Sun Oil Co.
and Bow Valley Exploration in Canada before moving to Denver in 1974, where he
was employed by Tesoro Petroleum and Southland Royalty Co. In 1977, he
co-founded Terra Marine Energy Co., which was sold in 1980 to Southport
Exploration. Mr. Wolf is also a director of MarkWest Hydrocarbon, Inc. and
Aspect Resources LLC, an affiliate of Aspect Management Corp. Mr. Wolf holds a
bachelor of science degree in business administration from Greenville College.

Barth E. Whitham, President, Chief Operating Officer and Secretary since
April 2000. Mr. Whitham joined Westport Oil and Gas at its inception in 1991,
where he held the positions of president and chief operating officer. Prior to
joining Westport Oil and Gas, Mr. Whitham was manager of production operations
for the Caza companies. From 1979 to 1991, he was associated with several U.S.
and Canadian oil and natural gas companies, including Pennzoil Exploration and
Production Co. and Pembina Resources Ltd., where his experience included
reservoir engineering, strategic planning, property evaluation and operations
management. Mr. Whitham holds a petroleum engineering degree and master of
science, mineral economics degree from Colorado School of Mines.

James H. Shonsey, Chief Financial Officer since April 2000. Mr. Shonsey
joined Westport Oil and Gas in 1997 as chief financial officer. Prior to joining
Westport Oil and Gas, Mr. Shonsey was vice president of finance for Snyder Oil
Corp., where he was employed since 1991. From 1987 to 1991, Mr. Shonsey served
in various capacities, including director of operations -- accounting for Apache
Corp. From 1976 to 1987, he held various positions with Deloitte & Touche,
Quantum Resources Corp., Flare Energy Corp. and Mizel Petro Resources Inc. Mr.
Shonsey holds a bachelor of science degree in business

51
<PAGE> 55

administration (accounting) from Regis University and a master of science degree
in business administration (accounting) from the University of Denver.

Kenneth D. Anderson, Vice President -- Accounting since April 2000. Mr.
Anderson joined Westport Oil and Gas in September 199l as controller. He has
spent the last 20 years in private industry, directly involved in the financial
management of oil and natural gas exploration and production companies. Mr.
Anderson holds a bachelor's degree in accounting and business administration
from Moorehead University.

Andrew M. Ashby, Vice President -- Operations Denver Division since April
2000. Mr. Ashby joined Westport Oil and Gas in January 1997 as senior operations
engineer for the Williston Basin. He began his career in 1978 as a petroleum
engineer with Amoco Production Co. He worked in this capacity and as an
exploration geologist for seven years with Amoco prior to becoming vice
president of exploration and production for Lynx Exploration Co. In 1990, he
became an independent exploration and engineering consultant and an independent
operator prior to joining Westport Oil and Gas. Mr. Ashby holds a bachelor of
science degree in geological engineering from the Colorado School of Mines.

Lynn S. Belcher, Vice President -- Business Development since April 2000.
Mr. Belcher joined Westport Oil and Gas in 1996 as vice president - land. He is
a 23-year veteran of the oil and natural gas industry. Mr. Belcher began his
career with Amoco Production Co. as a petroleum landman and later served in the
same position with Davis Oil Co. In 1985, he co-founded Focus Exploration, Inc.
and in 1992, Peak Energy Co., serving both Denver companies as vice
president-land. Mr. Belcher holds a bachelor of science degree in business
administration from Arizona State University.

Brian K. Bess, Vice President -- Engineering since April 2000. Mr. Bess
joined Westport Oil and Gas in 1998 as vice president - engineering. Prior to
joining Westport Oil and Gas, Mr. Bess was the acquisitions and reservoir
manager for General Atlantic Resources/UMC Petroleum Corp. from 1993 until 1998.
From 1981 to 1993 he held various engineering positions with Petro-Lewis Corp.,
Energy Investment Management, and General Royalty Companies, as well as various
consulting assignments. Mr. Bess holds a bachelor of science degree in petroleum
engineering from the University of Missouri - Rolla.

Klein P. Kleinpeter, Vice President and General Manager, Gulf Coast since
April 2000. Mr. Kleinpeter directs our production, exploitation and exploration
activities in the Gulf of Mexico, duties he was performing as senior vice
president for Equitable Production Company prior to the transaction between
Westport Oil and Gas and EPGC. He originally joined Equitable Production Company
in 1996 as a consultant. Mr. Kleinpeter held various management positions with
CNG Producing Company from 1985 to 1996. Earlier he held management and staff
positions with Aminoil and Atlantic Richfield. Mr. Kleinpeter holds a bachelor
of science degree in mechanical engineering from the University of Southwestern
Louisiana.

Michael Russell, Attorney at Law, Director since April 2000. Mr. Russell is
a partner of Dr. Richard J. Haas Partners, London, the Trust Lawyers who are
responsible worldwide for overseeing the affairs of the founder of Westport Oil
and Gas and the current major shareholder of Westport Resources. He is past
president and director of Westport Oil and Gas and has been involved in the U.S.
oil and natural gas industry for the past 20 years. He was called to the bar at
Lincoln's Inn, London and has worked for the partnership for 26 years. Together
with senior partner, Dr. Richard J. Haas, he was responsible for starting in
1981 the original U.S. oil and gas operations that led to the formation of
Westport Oil and Gas.

Murry S. Gerber, Director since April 2000. Mr. Gerber is chairman,
president and CEO of Equitable Resources, Inc. Prior to joining Equitable
Resources, Inc., Mr. Gerber served as chief executive officer of Coral Energy, a
joint venture of Shell Oil, Tejas Gas and Shell Canada. Prior to that, he held
various positions at Shell Oil, including treasurer. Mr. Gerber also serves on
the board of BlackRock, Inc. Mr. Gerber holds a master's degree in geology from
the University of Illinois and a bachelor's degree in geology from Augustana
College.

52
<PAGE> 56

David L. Porges, Director since April 2000. Mr. Porges is executive vice
president and chief financial officer of Equitable Resources, Inc. Mr. Porges
joined Equitable Resources, Inc. in 1998. Mr. Porges joined Bankers Trust in
1987 where he was a managing director from 1991 through 1998. He has been
involved in the oil and natural gas business, and financial services supporting
that business, for the past 20 years. Mr. Porges holds an Industrial
Engineering/Operations Research degree from Northwestern University and an MBA
from Stanford University.

James M. Funk, Director since April 2000. Mr. Funk joined Equitable
Resources, Inc. as president, Equitable Production Company in June 2000.
Previously during his 23 years at Shell Oil he held the positions of president,
Shell Continental Companies (1998), vice-president, Shell Offshore, Inc. and
general manager, Shelf E&P Business Unit (1991-1997), and chief executive
officer of Shell Midstream Enterprises, Inc. (1996-1997). Mr. Funk is a
certified petroleum geologist and has an AB degree in geology from Wittenberg
University, a master's degree in geology from the University of Connecticut and
a PhD in geology from the University of Kansas.

Alex M. Cranberg, Director since April 2000. Mr. Cranberg is president of
Aspect Management Corp., a Denver oil and natural gas exploration and investment
company. Mr. Cranberg was a director of Westport Oil and Gas prior to its
transaction with EPGC. He is a past director of General Atlantic Resources Inc.
and United Meridian Corp. He serves as a director of Brigham Oil & Gas Co. Mr.
Cranberg holds a petroleum engineering degree from the University of Texas and
an MBA from Stanford University.

William F. Wallace, Director since April 2000. Mr. Wallace is an advisory
member of the Beacon Alliance of the Beacon Group, a private investment and
venture capital fund recently purchased by Chase Manhattan Bank Group. Mr.
Wallace was a director of Westport Oil and Gas prior to the transaction with
EPGC. He also serves on the board of directors of Input/Output, Inc. and the
Khanty Mansiysk Oil Corp. Mr. Wallace was vice chairman of Barrett Resources in
1995. He served as president, chief operating officer and director of Plains
Petroleum Co. from 1994 to 1995. Prior to joining Plains Petroleum in 1994, Mr.
Wallace spent a combined total of 23 years with Texaco Inc., including six years
of service as vice president of exploration for Texaco USA and as regional vice
president of Texaco's Eastern Region, responsible for all exploration and
producing activities onshore and offshore throughout the eastern United States.
Mr. Wallace received an AB degree from Middlebury College and a master of
science degree from Stanford University.

CLASSES OF BOARD OF DIRECTORS

Our board of directors is composed of nine directors. Our board of
directors is divided into three classes that serve staggered three-year terms,
as follows:

<TABLE>
<CAPTION>
CLASS EXPIRATION OF TERM MEMBERS
----- ------------------ --------
<S> <C> <C>
Class 1...................................................
Class 2...................................................
Class 3...................................................
</TABLE>

Pursuant to a shareholders' agreement dated March 9, 2000, ERI Investments,
Inc. and Westport Energy LLC each have the right to designate three directors,
one to each class. The number of directors a party may designate is reduced if
such party decreases his ownership of our common stock. See "Certain
Transactions."

COMMITTEES OF THE BOARD OF DIRECTORS

Our board of directors has established an audit committee and a
compensation committee. Pursuant to the shareholders' agreement, each committee
of the board must have an equal number of ERI Investments, Inc. and Westport
Energy LLC designated directors.

53
<PAGE> 57

Audit Committee

The audit committee currently consists of Messrs. , and
. The audit committee is responsible for:

- recommending the selection of our independent accountants;

- reviewing and approving the scope of our independent accountants' audit
activity and extent of non-audit services;

- reviewing with management and the independent accountants the adequacy of
our basic accounting systems;

- reviewing our financial statements with management and the independent
accountants and exercising general oversight of our financial reporting
process; and

- reviewing our litigation and other legal matters that may affect our
financial condition and monitoring compliance with our business ethics
and other policies.

Compensation Committee

The compensation committee currently consists of Messrs. ,
, and . This committee's responsibilities include:

- administering and granting awards under our stock option plan;

- reviewing the compensation of our chief executive officer and
recommendations of the chief executive officer as to appropriate
compensation for our other executive officers and key personnel;

- examining periodically our general compensation structure; and

- supervising our welfare and pension plans and compensation plans.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

Donald D. Wolf serves on the board of directors for Aspect Resources LLC,
an affiliate of Aspect Management Corp. Alex M. Cranberg, a member of our board
of directors, is the President of Aspect Management Corp.

COMPENSATION OF DIRECTORS

Our outside directors receive a retainer of $10,000 per year for serving as
members of our board of directors, which they may elect to receive in the form
of shares of our common stock. In addition, each director receives $2,000 per
board meeting and $750 per sub-committee meeting attended and is granted an
annual stock option to purchase 3,000 shares of our common stock, which vests
annually over two years.

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<PAGE> 58

EXECUTIVE COMPENSATION

The following table sets forth certain summary information concerning the
compensation (at Westport Oil and Gas) of our chief executive officer and each
of the next four most highly compensated officers for 1999. The annual
compensation amounts in the table exclude perquisites and other personal
benefits for individuals for whom the aggregate amount of such compensation does
not exceed the lesser of (i) $50,000 or (ii) 10% of the total annual salary and
bonus for such named executive officer in that year.

SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
ANNUAL COMPENSATION
----------------------------------------
OTHER ANNUAL ALL OTHER
NAME AND PRINCIPAL POSITION SALARY ($) BONUS ($) COMPENSATION(1) COMPENSATION
--------------------------- ---------- --------- --------------- ------------
<S> <C> <C> <C> <C>
Donald D. Wolf.............................. $220,631 $80,000(2) $13,117 --
Chairman, Chief Executive Officer
Barth E. Whitham............................ 196,181 58,000(3) 12,533 --
President, Chief Operating Officer,
Secretary
Brian K. Bess............................... 140,000 73,500(4) -- --
Vice President -- Engineering
Allan D. Keel(5)............................ 152,381 36,684 -- --
Vice President -- Gulf of Mexico
Exploration
James H. Shonsey............................ 153,181 20,445(6) -- --
Chief Financial Officer
</TABLE>

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

(1) Includes an automobile allowance and club membership dues.
(2) Includes $30,000 paid in 1999 for services rendered in 1998.
(3) Includes $25,000 paid in 1999 for services rendered in 1998.
(4) Includes $50,000 paid in 1999 for services rendered in 1998.
(5) Mr. Keel resigned from Westport on April 21, 2000.
(6) Includes $8,500 paid in 1999 for services rendered in 1998.

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<PAGE> 59

OPTION GRANTS IN LAST FISCAL YEAR

The following tables set forth certain information concerning option grants
made (1) by Westport Oil and Gas to the named executive officers during 1999
pursuant to its stock option plan, which options were terminated in connection
with the transaction between Westport Oil and Gas and EPGC, and (2) by us to the
named executive officers during 2000 pursuant to our stock option plans. We were
formed in September 1999 and did not grant any options in 1999.

<TABLE>
<CAPTION>
WESTPORT OIL AND GAS FISCAL YEAR 1999
---------------------------------------------------
INDIVIDUAL GRANTS
--------------------------------------------------- POTENTIAL REALIZABLE VALUE
NUMBER OF PERCENTAGE OF AT ASSUMED ANNUAL RATES
SECURITIES TOTAL OPTIONS OF STOCK PRICE APPRECIATION
UNDERLYING GRANTED TO EXERCISE FOR OPTION TERM($)(2)
OPTIONS EMPLOYEES IN PRICE EXPIRATION ---------------------------
NAME AND PRINCIPAL POSITION GRANTED FISCAL YEAR(1) ($/SH) DATE 5% 10%
--------------------------- ---------- -------------- -------- ---------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Donald D. Wolf............................ 125,000 31.9% $12.00 4/1/09 $943,750 $2,390,000
Chairman, Chief Executive Officer 80,500 20.5 16.00 9/1/09 809,830 2,052,750
Barth E. Whitham.......................... 50,000 12.7 12.00 4/1/09 377,500 956,000
President, Chief Operating Officer,
Secretary............................. 15,400 3.9 16.00 9/1/09 154,924 392,700
Brian K. Bess............................. 12,000 3.1 12.00 4/1/09 90,600 229,440
Vice President -- Engineering
Allan D. Keel(3).......................... -- -- -- -- -- --
Vice President -- Gulf of Mexico
Exploration
James H. Shonsey.......................... 12,000 3.1 12.00 4/1/09 90,600 229,440
Chief Financial Officer
</TABLE>

<TABLE>
<CAPTION>
WESTPORT RESOURCES CORPORATION FISCAL YEAR 2000
--------------------------------------------------
INDIVIDUAL GRANTS
-------------------------------------------------- POTENTIAL REALIZABLE VALUE
NUMBER OF PERCENTAGE OF AT ASSUMED ANNUAL RATES
SECURITIES TOTAL OPTIONS OF STOCK PRICE APPRECIATION
UNDERLYING GRANTED TO EXERCISE FOR OPTION TERM($)(2)
OPTIONS EMPLOYEES IN PRICE EXPIRATION ----------------------------
NAME AND PRINCIPAL POSITION GRANTED 2000(4) ($/SH) DATE 5% 10%
--------------------------- ---------- ------------- -------- ---------- ------------ -------------
<S> <C> <C> <C> <C> <C> <C>
Donald D. Wolf........................... 500,000 48.4% $16.28 5/8/10 $5,120,000 $12,975,000
Chairman, Chief Executive Officer
Barth E. Whitham......................... 175,000 17.0 16.28 5/8/10 1,792,000 4,541,250
President, Chief Operating Officer,
Secretary
Brian K. Bess............................ 35,140 3.4 16.28 5/8/10 359,833 911,883
Vice President -- Engineering
Allan D. Keel(3)......................... -- -- -- -- -- --
Vice President -- Gulf of Mexico
Exploration
James H. Shonsey......................... 25,875 2.5 16.28 5/8/10 264,960 671,456
Chief Financial Officer
</TABLE>

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

(1) In 1999, Westport Oil and Gas granted options to purchase a total of 95,900
shares of common stock at an exercise price of $16.00 per share and options
to purchase a total of 296,500 shares of common stock at an exercise price
of $12.00 per share.

(2) In accordance with the rules of the SEC, the amounts shown on this table
represent hypothetical gains that could be achieved for the respective
options if exercised at the end of the option term. These gains are based on
the assumed rates of stock appreciation of 5% and 10% compounded annually
from the date the respective options were granted to their expiration date
and do not reflect our estimates or projections of the future price of our
common stock. The gains shown are net of the option exercise price, but do
not include deductions for taxes or other expenses associated with the
exercise. Actual gains, if any, on stock option exercises will depend on the
future performance of our common stock, the option holder's continued
employment through the option period, and the date on which the options are
exercised.

(3) Mr. Keel resigned from Westport on April 21, 2000.

(4) In 2000, we have granted options to purchase a total of 1,032,109 shares of
common stock at an exercise price of $16.28 per share.

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<PAGE> 60

EMPLOYMENT AGREEMENTS

Westport entered into an employment agreement with each of Donald D. Wolf
and Barth E. Whitham on May 8, 2000 to serve as Westport's chairman and chief
executive officer and its president, respectively. The initial term of each
employment agreement extends through May 31, 2003. During this term, Mr. Wolf
and Mr. Whitham will receive an annual base salary of $325,000 and $225,000,
respectively, subject to annual adjustments. In addition to the salary, Mr. Wolf
and Mr. Whitham received a stock option to acquire 500,000 shares and 175,000
shares, respectively, of our common stock at an exercise price of $16.28 per
share. The options vest ratably over three years. The agreements provide that if
any payments or distributions to Mr. Wolf or Mr. Whitham by Westport or any
affiliate are subject to Section 4999 of the Internal Revenue Code, Westport is
required to compensate such person for the amount of any excise tax imposed
pursuant to Section 4999 of the Internal Revenue Code and for any taxes imposed
on that additional payment. Section 4999 of the Internal Revenue Code addresses
additional taxes payable in the event of a change in control of Westport.

The employment agreements also provide for severance payments to Mr. Wolf
and Mr. Whitham if Westport terminates such person's employment other than for
cause or if such person's employment is terminated upon a change of control of
Westport. In such case, Westport must pay the individual an amount equal to
three times his then applicable base salary and three times the average of the
bonus he received for the last three years. The employment agreements also
include a non-competition provision for one year if the individual voluntarily
terminates his employment and a non-solicitation provision for one year
following the termination of such person's employment with Westport.

EMPLOYEE BENEFIT PLAN

Effective , 2000, we adopted the Westport Resources
Corporation 2000 Stock Incentive Plan. The plan merges, amends and restates the
EPGC Directors' Stock Option Plan and the EPGC 2000 Stock Option Plan, each of
which were adopted effective March 1, 2000. The current plan contains terms
regarding stock option awards that are substantially similar to the terms of the
predecessor plans, other than with respect to the vesting period for options
issued pursuant to the EPGC Directors' Stock Option Plan, which formerly vested
in full on the date of grant and now vest on a schedule determined by our
compensation committee. Further, the current plan contemplates awards of stock
appreciation rights, restricted stock and other performance awards, in addition
to the stock option grants contemplated by the predecessor plans.

We have reserved shares of our common stock for issuance under
the plan. As of , 2000, no options or other awards have been
granted under the plan. However, options to purchase an aggregate of 1,032,109
shares of our common stock were granted under the EPGC 2000 Stock Option Plan
and the EPGC Directors' Stock Option Plan. An aggregate of 16,357 of these
options held by certain of our current and former directors are fully vested and
immediately exercisable, and all of the options terminate not later than 10
years from the date of grant.

RETIREMENT SAVINGS PLAN

Effective December 1, 1995, Westport Oil and Gas adopted a retirement
savings plan that we assumed pursuant to the transaction between Westport Oil
and Gas Company and EPGC. This savings and profit sharing plan covers all of our
employees. The plan is subject to the provisions of the Employee Retirement
Income Security Act of 1974, as amended, and Section 401(k) of the Internal
Revenue Code.

The assets of the plan are held and the related investments are executed by
the plan's trustee. Participants in the plan have investment alternatives in
which to place their funds and may place their funds in one or more of these
investment alternatives. We pay all administrative fees on behalf of the plan.
The plan provides for discretionary matching by Westport of 60% of each
participant's contributions up to 6% of the participant's compensation. Westport
Oil and Gas contributed $114,000 and $104,000 for the year ended December 31,
1999 and 1998, respectively.

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<PAGE> 61

ANNUAL INCENTIVE PLAN

The Westport Annual Incentive Plan 2000 provides an opportunity for certain
employees within a business unit to be eligible for a bonus based on both
Westport and the business unit achieving various performance objectives. Under
the plan, the administrator of the plan annually determines the goals that each
business unit must achieve, as well as the target bonus amount for achieving the
goals. The administrator also establishes the company performance goal, which
must be achieved before any bonuses will be paid out under this plan. If
Westport obtains its performance goal and the individual business units achieve
their respective goals, 25% of the bonus amount will be paid out to each
participating employee within the business unit and 75% of the bonus will be
awarded to various individuals within the business unit on a discretionary
basis.

ROYALTY PARTICIPATION PROGRAM

On October 17, 1997, Westport Overriding Royalty LLC was established,
through which we implemented a royalty participation program. This program is
designed to provide an incentive for certain key employees to contribute to our
success. Under the terms of the program, participants can receive a percentage
of an overriding royalty working interest on prospects owned by us. Percentages
are established at our discretion, but in no event exceed 2% of our net
interest. Effective March 31, 2000, none of our officers or directors are
eligible to receive royalties from this program.

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<PAGE> 62

CERTAIN TRANSACTIONS

SHAREHOLDERS' AGREEMENT

In connection with the transaction between Westport Oil and Gas and EPGC,
we entered into a shareholders' agreement with Westport Energy LLC and Equitable
Production Company. Equitable Production Company's stock in Westport was
subsequently transferred to ERI Investments, Inc., a Delaware corporation and
wholly-owned subsidiary of Equitable Resources, Inc. In addition, Barth E.
Whitham and Donald D. Wolf Family Limited Partnership have granted Westport
Energy LLC the power and authority to subject the shares of Westport issued to
such stockholders to the provisions in the shareholders' agreement. The
shareholders' agreement contains several provisions, including:

- a voting agreement whereby the parties must vote their shares according
to the shareholders' agreement;

- prior to a qualified public offering (as such term is defined in the
shareholders' agreement), the board of directors is to be comprised of
nine directors, three of whom are to be designated by ERI Investments,
Inc. and three of whom are to be designated by Westport Energy LLC. In
addition, each of ERI Investments, Inc. and Westport Energy LLC shall
designate one independent director (as such term is defined in the
shareholders' agreement). The final director position is to be filled by
our chief executive officer;

- following a qualified public offering (as such term is defined in the
shareholders' agreement), each of ERI Investments, Inc. and Westport
Energy LLC has the right to designate three directors, one to each class.
The number of directors a party may designate is reduced if such party
decreases its ownership of our common stock;

- if each of ERI Investments, Inc. and Westport Energy LLC has the right to
appoint at least two directors, the approval of two-thirds of the board
of directors may be required to approve certain acquisitions and
dispositions;

- following a qualified public offering (as such term is defined in the
shareholders' agreement) and subject to certain conditions, neither ERI
Investments, Inc. nor Westport Energy LLC will acquire any additional
shares of our common stock without the consent of the other;

- each of ERI Investments, Inc. and Westport Energy LLC is granted
unlimited piggyback registration rights;

- each of ERI Investments, Inc. and Westport Energy LLC is granted three
demand registration rights; and

- the parties agree to enter into holdback agreements if requested by the
underwriters in underwritten offerings.

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<PAGE> 63

PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth certain information with respect to the
beneficial ownership of our common stock as of June 15, 2000, and as adjusted to
reflect the sale of the common stock being offered hereby and assuming no
exercise of the underwriter's over-allotment option, by:

- each of our directors and executive officers;

- all our directors and executive officers as a group;

- each person, or group of affiliated persons, who is known by us to own
beneficially more than 5% of our common stock; and

- each selling stockholder.

<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP
PRIOR TO THE OFFERING(1) SHARES TO BE AFTER THE OFFERING
------------------------ SOLD --------------------
NAME NUMBER PERCENT IN THE OFFERING NUMBER PERCENT
---- ------------ --------- --------------- ---------- -------
<S> <C> <C> <C> <C> <C>
Directors and Executive Officers:
Donald D. Wolf(2)............... 22,500 *% -- 22,500 *%
Barth E. Whitham(3)............. 22,500 * -- 22,500 *
James H. Shonsey(4)............. -- -- -- -- --
Kenneth D. Anderson(5).......... -- -- -- -- --
Andrew M. Ashby(6).............. -- -- -- -- --
Lynn S. Belcher(7).............. -- -- -- -- --
Brian K. Bess(8)................ -- -- -- -- --
Klein P. Kleinpeter(9).......... -- -- -- -- --
Michael Russell................. -- -- -- -- --
Murry S. Gerber................. -- -- -- -- --
David L. Porges................. -- -- -- -- --
James M. Funk................... -- -- -- -- --
Alex M. Cranberg(10)............ 5,679 * -- 5,679 --
William F. Wallace(11).......... 4,999 * -- 4,999 --
Five Percent Beneficial Owners and
Selling Stockholders:
Westport Energy LLC............. 10,375,334 50.4
21 Glen Oaks Ave.
Summit, NJ 07901
ERI Investments, Inc............ 10,157,435 49.4
One Oxford Centre, Suite 3300
Pittsburgh, PA 15219
</TABLE>

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

* Less than one percent.

(1) Beneficial ownership is determined in accordance with the rules of the SEC
and generally includes voting or investment power with respect to
securities. Shares of common stock subject to options, warrants and
convertible notes currently exercisable or convertible, or exercisable or
convertible within 60 days of June 15, 2000 are deemed outstanding for
computing the percentage of the person or entity holding such securities,
but are not outstanding for computing the percentage of any other person or
entity. Except as indicated by footnote and subject to community property
laws where applicable, the persons named in the table above have sole
voting and investment power with respect to all shares of common stock
shown as beneficially owned by them.

(2) These shares are held by Donald D. Wolf Family Limited Partnership. Mr.
Wolf holds options to purchase 500,000 shares of common stock, none of
which are exercisable within 60 days of June 15, 2000.

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<PAGE> 64

(3) Mr. Whitham holds options to purchase 175,000 shares of common stock, none
of which are exercisable within 60 days of June 15, 2000.

(4) Mr. Shonsey holds options to purchase 25,875 shares of common stock, none
of which are exercisable within 60 days of June 15, 2000.

(5) Mr. Anderson holds options to purchase 11,596 shares of common stock, none
of which are exercisable within 60 days of June 15, 2000.

(6) Mr. Ashby holds options to purchase 20,906 shares of common stock, none of
which are exercisable within 60 days of June 15, 2000.

(7) Mr. Belcher holds options to purchase 53,221 shares of common stock, none
of which are exercisable within 60 days of June 15, 2000.

(8) Mr. Bess holds options to purchase 35,140 shares of common stock, none of
which are exercisable within 60 days of June 15, 2000.

(9) Mr. Kleinpeter holds options to purchase 30,000 shares of common stock,
none of which are exercisable within 60 days of June 15, 2000.

(10) Mr. Cranberg holds options to purchase 5,679 shares of common stock, which
are exercisable within 60 days of June 15, 2000.

(11) Mr. Wallace holds options to purchase 4,999 shares of common stock, which
are exercisable within 60 days of June 15, 2000.

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<PAGE> 65

DESCRIPTION OF CAPITAL STOCK

On the closing of this offering, our authorized capital stock will consist
of shares of common stock, $0.01 par value, and shares of
preferred stock, $0.01 par value.

COMMON STOCK

As of May 31, 2000, there were 20,577,769 shares of common stock
outstanding that were held of record by four stockholders. As of May 31, 2000,
there were 1,032,109 shares of common stock subject to outstanding options,
16,357 of which are currently exercisable. There will be shares of common
stock outstanding (assuming no exercise of the underwriters' over-allotment
option and assuming no exercise after , 2000, of outstanding options
or warrants) after giving effect to the sale of the shares of common stock to
the public in this offering. The holders of common stock are entitled to one
vote per share on all matters to be voted on by the stockholders. Subject to
preferences that may be applicable to any outstanding preferred stock, the
holders of common stock are entitled to receive ratable dividends, if any, as
may be declared from time to time by the board of directors out of funds legally
available for the payment of dividends. In the event of the liquidation,
dissolution, or winding up of Westport, the holders of common stock are entitled
to share ratably in all assets remaining after payment of liabilities, subject
to prior distribution rights of preferred stock, if any, then outstanding. The
common stock has no preemptive, conversion or other subscription rights. There
are no redemption or sinking fund provisions applicable to the common stock. All
outstanding shares of common stock are fully paid and nonassessable, and the
shares of common stock to be issued upon completion of this offering will be
fully paid and nonassessable.

PREFERRED STOCK

On the closing of this offering, 5,000,000 shares of preferred stock will
be authorized and no shares will be outstanding. The board of directors, without
further vote or action by the stockholders, has the authority to issue the
preferred stock in one or more series and to fix the rights, preferences,
privileges and restrictions thereof, including dividend rights, dividend rates,
conversion rights, voting rights, terms of redemption, redemption prices,
liquidation preferences and the number of shares constituting any series or the
designation of such series. The issuance of preferred stock may have the effect
of delaying, deferring or preventing a change in control of Westport without
further action by the stockholders and may adversely affect the voting and other
rights of the holders of common stock. The issuance of preferred stock with
voting and conversion rights may adversely affect the voting power of the
holders of common stock, including the loss of voting control to others. We
currently have no plans to issue any of the preferred stock.

ANTI-TAKEOVER EFFECTS OF PROVISIONS OF OUR CERTIFICATE OF INCORPORATION, BYLAWS
AND DELAWARE LAW

Certificate of Incorporation and Bylaws

Our certificate of incorporation to be effective upon consummation of this
offering provides that the board of directors will be divided into three classes
of directors, with each class serving a staggered three-year term. The
classification system of electing directors may tend to discourage a third-party
from making a tender offer or otherwise attempting to obtain control of Westport
and may maintain the incumbency of the board of directors, as the classification
of the board of directors generally increases the difficulty of replacing a
majority of the directors. The certificate of incorporation and bylaws also
provide, among other things, that, effective on the closing of this offering:

- all stockholder actions must be effected at a duly called meeting and not
by a consent in writing;

- special meetings of the stockholders may only be called by our chairman,
president or secretary;

- stockholders must provide Westport advance notice if they wish to
nominate a director or propose any business at a stockholders meeting;

62
<PAGE> 66

- directors may be removed only for cause by a majority vote of the
outstanding shares of voting stock; and

- any vacancies on the board of directors may be filled by a majority of
the directors continuing in office.

These provisions of the certificate of incorporation and bylaws could
discourage potential acquisition proposals and could delay or prevent a change
of control of Westport. These provisions are intended to enhance the likelihood
of continuity and stability in the composition of the board of directors and in
the policies formulated by the board of directors and to discourage certain
types of transactions that may involve an actual or threatened change of control
of Westport. These provisions are designed to reduce our vulnerability to an
unsolicited acquisition proposal. The provisions also are intended to discourage
certain tactics that may be used in proxy fights. However, such provisions could
have the effect of discouraging others from making tender offers for our shares
and, as a consequence, they also may inhibit fluctuations in the market price of
our shares that could result from actual or rumored takeover attempts. Such
provisions also may have the effect of preventing changes in our management.

Delaware Takeover Statute

We are subject to Section 203 of the Delaware General Corporation Law, or
DGCL Section 203, which regulates corporate acquisitions. DGCL Section 203
prevents certain Delaware corporations, including those whose securities are
listed on the New York Stock Exchange from engaging, under certain
circumstances, in a "business combination" with any "interested stockholder" for
three years following the date that such stockholder became an interested
stockholder. For purposes of DGCL Section 203, a "business combination"
includes, among other things, a merger or consolidation involving Westport and
the interested stockholder and the sale of 10% or more of our assets. In
general, DGCL Section 203 defines an "interested stockholder" as any entity or
person beneficially owning 15% or more of our outstanding voting stock and any
entity or person affiliated with or controlling or controlled by such entity or
person. A Delaware corporation may "opt out" of DGCL Section 203 with an express
provision in its original certificate of incorporation or an express provision
in its certificate of incorporation or bylaws resulting from amendments approved
by the holders of at least a majority of our outstanding voting shares. We have
not "opted out" of the provisions of DGCL Section 203.

REGISTRATION RIGHTS

After this offering, the holders of approximately 20,532,769 shares of
common stock or rights to acquire such shares will be entitled to rights with
respect to the registration of such shares under the Securities Act. Under the
terms of the agreement between us and the holders of such registrable
securities, if we propose to register any of our securities under the Securities
Act, either for our own account or for the account of other security holders
exercising registration rights, such holders are entitled to notice of such
registration and are entitled to include shares of such common stock in the
registration. Additionally, such holders are also entitled to demand
registration rights, pursuant to which they may require us on up to three
occasions to file a registration statement under the Securities Act at our
expense with respect to their shares of common stock, and we are required to use
all reasonable efforts to effect such registration. All of these registration
rights are subject to certain conditions and limitations, including the right of
the underwriters of an offering to limit the number of shares included in such
registration and our right not to effect a requested registration within 180
days following an offering of our securities, including the offering made by
this prospectus.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common stock is American
Securities Transfer & Trust, Inc.

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<PAGE> 67

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no market for our common stock, and
we cannot assure you that a significant public market for our common stock will
develop or be sustained after this offering. Sales of substantial amounts of our
common stock in the public market could cause the market price of our common
stock to fall and could affect our ability to raise capital on terms favorable
to us in the future.

Upon completion of this offering, we will have outstanding shares
of common stock, assuming the underwriters' over-allotment option is not
exercised. Of these shares, shares, or shares if the
underwriters exercise their over-allotment option in full, of the common stock
sold in this offering will be freely tradable without restriction under the
Securities Act unless purchased by our affiliates as that term is defined in
Rule 144 under the Securities Act. The remaining shares of common
stock outstanding will be restricted securities under Rule 144 and may in the
future be sold without registration under the Securities Act to the extent
permitted by Rule 144 or any other applicable exemption under the Securities
Act, subject to the restrictions on transfer contained in the shareholders'
agreement and described in "Certain Transactions" and the lock-up agreements
described in "Underwriting."

RULE 144

In general, under Rule 144 as currently in effect, beginning 90 days after
the date of this prospectus, a person, or persons whose shares are aggregated,
who has beneficially owned restricted shares for at least one year, including
the holding period of any prior owner except an affiliate, would be entitled to
sell within any three-month period a number of shares that does not exceed the
greater of:

- one percent of the number of shares of common stock then outstanding,
which will equal approximately shares immediately after this
offering; or

- the average weekly trading volume of the common stock during the four
calendar weeks preceding the filing of a Form 144 with respect to the
sale.

Sales under Rule 144 also are subject to manner of sale provisions and
notice requirements and to the availability of current public information about
us. Under Rule 144(k), a person who is not deemed to have been an affiliate of
us at any time during the three months preceding a sale and who has beneficially
owned the shares proposed to be sold for at least two years, including the
holding period of any prior owner except an affiliate, is entitled to sell those
shares without complying with the manner of sale, public information, volume
limitation or notice provisions of Rule 144.

RULE 701

Rule 701 permits resales of shares in reliance on Rule 144 but without
compliance with specified restrictions of Rule 144. Any employee, officer or
director of or consultant to Westport who purchased his or her shares under a
written compensatory plan or contract may be entitled to rely on the resale
provisions of Rule 701. Rule 701 permits affiliates to sell their Rule 701
shares under Rule 144 without complying with the holding period requirements of
Rule 144. Rule 701 further provides that non-affiliates may sell those shares in
reliance on Rule 144 without having to comply with the holding period, public
information, volume limitation or notice provisions of Rule 144. All holders of
Rule 701 shares are required to wait until 90 days after the date of this
prospectus before selling those shares.

STOCK OPTIONS

Following the consummation of this offering, we intend to file a
registration statement on Form S-8 under the Securities Act covering shares of
common stock reserved for issuance under our stock option plan. Based on the
number of shares currently reserved for issuance under the plan that
registration statement would cover up to shares issuable on exercise
of the options, of which options will have been issued as of the date
of this offering. The registration statement on Form S-8 will automatically
become effective upon filing. Accordingly, subject to the exercise of those
options, shares registered under that registration statement will be available
for sale in the open market immediately after the 180-day lock-up agreements
expire.

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<PAGE> 68

UNITED STATES TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following general discussion summarizes some of the material United
States Federal income and estate tax consequences of the ownership and
disposition of our common stock by a non-U.S. holder of common stock. A non-U.S.
holder is a holder of common stock that is not, for United States Federal income
tax purposes, any of the following:

- a citizen or resident of the United States;

- a corporation, partnership or other entity created or organized in or
under the laws of the United States or any of its political subdivisions;

- an estate, the income of which is subject to U.S. Federal income taxation
regardless of its source; or

- a trust whose administration is subject to the primary supervision of a
U.S. court, and which has one or more U.S. persons who have the authority
to control all substantial decisions of the trust.

If a partnership is a beneficial owner of our common stock, the tax
treatment of a partner will generally depend upon the status of the partner and
upon the activities of the partnership. If you are a partner of a partnership
holding common stock, you should consult your tax advisor about the U.S. tax
consequences of holding and disposing of shares of our common stock.

This discussion does not consider all aspects of U.S. Federal income and
estate taxation or the specific facts and circumstances that may be relevant to
particular non-U.S. holders in light of their personal circumstances, such as
insurance companies, tax-exempt organizations, financial institutions,
broker-dealers or certain U.S. expatriates, and does not address the treatment
of those holders under the laws of any state, local or foreign taxing
jurisdiction. Further, the discussion is based on provisions of the United
States Internal Revenue Code of 1986, as amended, or the "Code," Treasury
regulations under the Code, and administrative and judicial interpretations of
the Code. This discussion is based on the provisions of the Code as they are in
effect on the date of this prospectus. All of these provisions are subject to
change or different interpretation on a possibly retroactive basis. This
discussion is limited to non-U.S. holders who hold the common stock as a capital
asset. Each prospective holder is urged to consult its tax advisor with respect
to the United States Federal income and estate tax consequences of acquiring,
holding and disposing of common stock, as well as any tax consequences that may
arise under the laws of any state, local or foreign taxing jurisdiction.

Dividends

Dividends paid to a non-U.S. holder of common stock generally will be
subject to United States Federal withholding tax at a 30% rate or a lower rate
as may be specified by an applicable income tax treaty. Provided that such
non-U.S. holder complies with applicable certification and disclosure
requirements, there will be no withholding tax with respect to dividends that
are effectively connected with the non-U.S. holder's conduct of a trade or
business within the United States (and if an income tax treaty applies, are
attributable to a United States permanent establishment of such non-U.S.
holder). Instead, the "effectively connected" dividends will be subject to net
U.S. Federal income tax in the same manner as dividends paid to United States
citizens, resident aliens and domestic United States corporations. Any
effectively connected dividends received by a corporate non-U.S. holder may
also, under certain circumstances, be subject to an additional "branch profits
tax" at a 30% rate or a lower rate as may be specified by an applicable income
tax treaty.

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<PAGE> 69

Under currently effective United States Treasury regulations, dividends
paid prior to January 1, 2001 to an address in a foreign country are presumed to
be paid to a resident of that country, unless the payor has knowledge to the
contrary, for purposes of the withholding discussed above and for purposes of
determining the applicability of a tax treaty rate. Under recently finalized
United States Treasury regulations that will generally be effective for
distributions after December 31, 2000, or the "Final Withholding Regulations,"
however, a non-U.S. holder of common stock who wishes to claim the benefit of an
applicable treaty rate would be required to satisfy applicable certification
requirements. In addition, under the Final Withholding Regulations, in the case
of common stock held by a foreign partnership, (1) the certification
requirements would generally be applied to the partners of the partnership and
(2) the partnership would be required to provide certain information, including
a United States taxpayer identification number. The Final Withholding
Regulations provide look-through rules for tiered partnerships.

The foregoing rules apply to distributions to shareholders out of our
current or accumulated earnings and profits. Different withholding rules will
apply to any distributions that we pay in excess of our current or accumulated
earnings and profits.

A non-U.S. holder of common stock that is eligible for a reduced rate of
United States withholding tax under a tax treaty may obtain a refund of any
excess amounts currently withheld by filing an appropriate claim for refund with
the United States Internal Revenue Service.

Gain On Disposition Of Common Stock

A non-U.S. holder generally will not be subject to United States Federal
income tax for gain recognized on a sale or other disposition of common stock
unless one of the following conditions is satisfied:

- the gain is effectively connected with a trade or business conducted by
the non-U.S. holder in the United States (and, if an income tax treaty
applies, is attributable to a permanent establishment maintained in the
United States by such non-U.S. holder). The non-U.S. holder will, unless
an applicable treaty provides otherwise, be taxed on its net gain derived
from the sale or other disposition under regular graduated U.S. Federal
income tax rates. Effectively connected gains realized by a corporate
non-U.S. holder may also, under certain circumstances, be subject to an
additional "branch profits tax" at a 30% rate or a lower rate as may be
specified by an applicable income tax treaty;

- in the case of a non-U.S. holder who is an individual and holds the
common stock as a capital asset, the holder is present in the United
States for 183 or more days in the taxable year of the sale or other
disposition and certain other conditions exist;

- we are or have been a "United States real property holding corporation"
for U.S. Federal income tax purposes within the shorter of the five-year
period preceding such disposition or such non-U.S. holder's holding
period. We believe we are currently, and are likely to remain, a "United
States real property holding corporation" for U.S. Federal income tax
purposes. The preceding sentence notwithstanding, under currently
effective United States Treasury regulations, any gain recognized by a
non-U.S. holder still would not be subject to U.S. Federal income tax if
the shares were considered to be "regularly traded on an established
securities market," and the non-U.S. holder did not hold, directly or
indirectly at any time during the shorter of the periods described above,
more than 5% of the common stock; or

- the non-U.S. holder is subject to tax under certain provisions of the
Code applicable to U.S. expatriates.

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<PAGE> 70

Federal Estate Tax Consequences

Common stock held by an individual non-U.S. holder at the time of death
will be included in such holder's gross estate for U.S. Federal estate tax
purposes, and may be subject to U.S. Federal estate tax, unless an applicable
estate tax treaty provides otherwise.

Information Reporting and Backup Withholding

We must report annually to the United States Internal Revenue Service and
to each non-U.S. holder the amount of dividends paid to, and the tax withheld
with respect to, such holder, regardless of whether any tax was actually
withheld. This information may also be made available to the tax authorities in
the non-U.S. holder's country of residence. Under current law, United States
information reporting requirements, other than reporting of dividend payments
for purposes of the withholding tax noted above, and backup withholding tax
generally will not apply to dividends paid to non-U.S. holders that are either
subject to the 30% withholding discussed above or that are not subject to
withholding because an applicable tax treaty reduces or eliminates the
withholding. Otherwise, backup withholding of United States Federal income tax
at a rate of 31% may apply to dividends paid with respect to common stock to
holders that are not "exempt recipients" and that fail to provide certain
information including the holder's United States taxpayer identification number.

Under current law, generally, unless the payor of dividends has actual
knowledge that the payee is a United States person, the payor may treat dividend
payments to a payee with a foreign address as exempt from information reporting
and backup withholding. However, under the Final Withholding Regulations,
dividend payments generally will be subject to information reporting and backup
withholding unless applicable certification requirements are satisfied. See the
discussion above with respect to the rules applicable to foreign partnerships
under the Final Withholding Regulations.

In general, United States information reporting and backup withholding
requirements also will not apply to a payment made outside the United States of
the proceeds of a sale of common stock to or through an office outside the
United States of a non-United States broker. However, United States information
reporting, but not backup withholding, requirements will apply to a payment made
outside the United States of the proceeds of a sale of common stock through an
office outside the United States of a broker that is a United States person or a
"United States related person" that derives 50% or more of its gross income for
certain periods from the conduct of a trade or business in the United States,
that is a "controlled foreign corporation" for United States Federal income tax
purposes, or, in the case of payments made after December 31, 2000, a foreign
partnership with certain connections to the United States, unless the broker has
documentary evidence in its records that the holder or beneficial owner is a
non-United States person or the holder or beneficial owner otherwise establishes
an exemption. Payment of the proceeds of the sale of common stock to or through
a United States office of a broker is currently subject to both United States
backup withholding and information reporting unless the holder certifies its
non-United States status under penalties of perjury or otherwise establishes an
exemption.

Backup withholding is not an additional tax. Amounts withheld under the
backup withholding rules are generally allowable as a refund or credit against
such non-U.S. holder's Federal income tax liability, if any, provided that the
required information is furnished to the IRS.

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<PAGE> 71

UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting
agreement, dated , 2000, we and the selling stockholders have agreed
to sell to the underwriters named below, for whom Credit Suisse First Boston
Corporation, Donaldson, Lufkin & Jenrette Securities Corporation, Lehman
Brothers Inc., Banc of America Securities LLC and Petrie Parkman & Co., Inc. are
acting as representatives, the following respective numbers of shares of our
common stock:

<TABLE>
<CAPTION>
NUMBER
UNDERWRITER OF SHARES
----------- ---------
<S> <C>
Credit Suisse First Boston Corporation......................
Donaldson, Lufkin & Jenrette Securities Corporation.........
Lehman Brothers Inc. .......................................
Banc of America Securities LLC..............................
Petrie Parkman & Co., Inc. .................................
--------
Total.............................................
========
</TABLE>

The underwriting agreement provides that the underwriters are obligated to
purchase all the shares of common stock in the offering if any are purchased,
other than those shares covered by the over-allotment option described below.
The underwriting agreement also provides that if an underwriter defaults, the
purchase commitments of non-defaulting underwriters may be increased or the
offering of common stock may be terminated.

The selling stockholders have granted to the underwriters a 30-day option
to purchase on a pro rata basis up to additional shares at the initial
public offering price less the underwriting discounts and commissions. The
option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at
the public offering price on the cover page of this prospectus and to the
selling group members at that price less a concession of $ per share. The
underwriters and the selling group members may allow a discount of $ per
share on sales to other broker/dealers. After the initial public offering, the
public offering price and concession and discount to broker/dealers may be
changed by the representatives.

The following table summarizes the compensation and estimated expenses we
and the selling stockholders will pay.

<TABLE>
<CAPTION>
PER SHARE TOTAL
------------------------------- -------------------------------
WITHOUT WITH WITHOUT WITH
OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Underwriting Discounts and Commissions
paid by us............................. $ $ $ $
Expenses payable by us................. $ $ $ $
Underwriting Discounts and Commissions
paid by the selling stockholders....... $ $ $ $
Expenses payable by the selling
stockholders........................... $ $ $ $
</TABLE>

The underwriters have informed us that they do not expect discretionary
sales to exceed 5% of the shares of common stock being offered.

Bank of America, N.A. is the agent and a lender under our credit agreement.
We have paid Bank of America, N.A. customary interest, fees and compensation in
connection with our credit agreement. We intend to use more than 10% of the net
proceeds from the sale of the common stock to repay a portion of the
indebtedness owed by us to Bank of America, N.A. under the credit agreement.
Accordingly, the offering is being made in compliance with the requirements of
Rule 2710(c)(8) of the National Association of Securities Dealers, Inc. Conduct
Rules. This rule provides generally that if more than 10%

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<PAGE> 72

of the net proceeds from the sale of stock, not including underwriting
compensation, is paid to the underwriters or their affiliates, the initial
public offering price of the stock may not be higher than that recommended by a
"qualified independent underwriter" meeting certain standards. Accordingly,
Credit Suisse First Boston Corporation is assuming the responsibilities of
acting as the qualified independent underwriter in pricing the offering and
conducting due diligence. Credit Suisse First Boston will be paid a fee of
$10,000 for its services as qualified independent underwriter. The initial
public offering price of the shares of common stock is no higher than the price
recommended by Credit Suisse First Boston Corporation.

We have agreed that we will not offer, sell, contract to sell, pledge or
otherwise dispose of, directly or indirectly, or file with the Securities and
Exchange Commission a registration statement under the Securities Act relating
to, any shares of our common stock or securities convertible into or
exchangeable or exercisable for any shares of our common stock, or publicly
disclose the intention to make any such offer, sale, pledge, disposition or
filing, without the prior written consent of Credit Suisse First Boston
Corporation for a period of 180 days after the date of this prospectus, except
for grants of employee stock options pursuant to the terms of any plan in effect
on the date of this prospectus, issuances of securities pursuant to the exercise
of employee stock options outstanding on the date of this prospectus and
employee stock purchases pursuant to the terms of a plan in effect on the date
of this prospectus.

All of our existing stockholders, executive officers and directors have
agreed that they will not offer, sell, contract to sell, pledge or otherwise
dispose of, directly or indirectly, any shares of our common stock or securities
convertible into or exchangeable or exercisable for any shares of our common
stock, enter into a transaction which would have the same effect, or enter into
any swap, hedge or other arrangement that transfers, in whole or in part, any of
the economic consequences of ownership of our common stock, whether any such
aforementioned transaction is to be settled by delivery of our common stock or
such other securities, in cash or otherwise, or publicly disclose the intention
to make any such offer, sale, pledge or disposition, or to enter into any such
transaction, swap, hedge or other arrangement, without, in each case, the prior
written consent of Credit Suisse First Boston Corporation for a period of 180
days after the date of this prospectus.

The underwriters have reserved for sale, at the initial public offering
price, up to shares of the common stock for employees, directors and
certain other persons associated with us who have expressed an interest in
purchasing common stock in the offering. The number of shares available for sale
to the general public in the offering will be reduced to the extent such persons
purchase these reserved shares. Any reserved shares not so purchased will be
offered by the underwriters to the general public on the same terms as the other
shares.

We and the selling stockholders have agreed to indemnify the underwriters
against liabilities under the Securities Act, or contribute to payments which
the underwriters may be required to make in that respect.

We intend to apply for the listing of our common stock on The New York
Stock Exchange under the symbol "WRC."

In connection with the transaction between Westport Oil and Gas and EPGC,
Petrie Parkman & Co., Inc. and Lehman Brothers Inc. provided investment banking
and financial advisory services to Westport Energy LLC and Equitable Resources,
Inc., respectively, for which they received customary fees.

69
<PAGE> 73

Prior to this offering, there has been no public market for our common
stock. The initial public offering price was determined by negotiation between
us and the representatives, and may not reflect the market price for our common
stock that may prevail following this offering. We considered, among others, the
following principal factors in determining the initial public offering price:

- the information in this prospectus and otherwise available to the
representatives;

- market conditions for initial public offerings;

- the history of and prospects for the industry in which we will compete;

- our past and present operations;

- our past and present earnings and current financial position;

- the ability of our management;

- our prospects for future earnings;

- the present state of our development and our current financial condition;

- the recent prices of, and the demand for, publicly traded common stock of
generally comparable companies; and

- the general condition of the securities markets at the time of this
offering.

We can offer no assurance that the initial public offering price will
correspond to the price at which our common stock will trade in the public
market subsequent to this offering or that an active trading market for our
common stock will develop and continue after this offering.

In connection with the offering the underwriters may engage in stabilizing
transactions, over-allotment transactions, syndicate covering transactions and
penalty bids in accordance with Regulation M under the Exchange Act.

- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.

- Over-allotment involves sales by the underwriters of shares in excess of
the number of shares the underwriters are obligated to purchase, which
creates a syndicate short position. The short position may be either a
covered short position or a naked short position. In a covered short
position, the number of shares over-allotted by the underwriters is not
greater than the number of shares, which they may purchase in the
over-allotment option. In a naked short position, the number of shares
involved is greater than the number of shares in the over-allotment
option. The underwriters may close out any short position by either
exercising their over-allotment option and/or purchasing shares in the
open market.

- 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. In determining the source of shares to
close out the short position, the underwriters will consider, among other
things, the price of shares available for purchase in the open market as
compared to the price at which they may purchase shares through the
over-allotment option. If the underwriters sell more shares than could be
covered by the over-allotment option -- a naked short position -- that
position can only be closed out by buying shares in the open market. A
naked short position is more likely to be created if the underwriters are
concerned that there may be downward pressure on the price of the shares
in the open market after pricing that could adversely affect investors
who purchase in the offering.

- Penalty bids permit the representatives to reclaim a selling concession
from a syndicate member when the common stock originally sold by the
syndicate member is purchased in a stabilizing or syndicate covering
transaction to cover syndicate short positions.

70
<PAGE> 74

These stabilizing transactions, syndicate covering transactions and penalty bids
may have the effect of raising or maintaining the market price of the common
stock or preventing or retarding a decline in the market price of the common
stock. As a result the price of the common stock may be higher than the price
that might otherwise exist in the open market. These transactions may be
effected on The New York Stock Exchange or otherwise and, if commenced, may be
discontinued at any time.

A prospectus in electronic format may be made available on the web sites
maintained by one or more of the underwriters participating in this offering.
The representatives may agree to allocate a number of shares to underwriters for
sale to their online brokerage account holders. Internet distributions will be
allocated by the underwriters that will make internet distributions on the same
basis as other allocations.

71
<PAGE> 75

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 we and the selling
stockholders 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 may 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 the common stock in Canada who receives a purchase
confirmation will be deemed to represent to us, the selling stockholders and the
dealer from whom such purchase confirmation is received that (i) such purchaser
is entitled under applicable provincial securities laws to purchase our common
stock without the benefit of a prospectus qualified under such securities laws,
(ii) where required by law, 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
Ontario securities law. 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 and the selling stockholders 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 10 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 us. Only one such report must be
filed in respect of shares of our common stock acquired on the same date and
under the same prospectus exemption.

TAXATION AND ELIGIBILITY FOR INVESTMENT

Canadian purchasers of the common stock should consult their own legal and
tax advisors about 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.

72
<PAGE> 76

LEGAL MATTERS

Certain legal matters with respect to the common stock offered hereby have
been passed upon for Westport by Akin, Gump, Strauss, Hauer & Feld, L.L.P. The
underwriters have been represented by Cravath, Swaine & Moore, New York, New
York.

EXPERTS

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

The audited statements of revenues and direct operating expenses for the
EPGC Properties included in this prospectus and elsewhere in the registration
statement have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their report with respect thereto, and are included
herein in reliance upon the authority of said firm as experts in giving said
report.

INDEPENDENT PETROLEUM ENGINEERS

The estimated reserve evaluations and related calculations of Ryder Scott
Company L.P. and Netherland, Sewell & Associates, Inc., our independent
petroleum engineers, have been included in this prospectus in reliance upon
authority of those firms as experts in petroleum engineering.

WHERE YOU CAN FIND MORE INFORMATION

This prospectus is part of a registration statement we have filed with the
SEC relating to our common stock. As permitted by SEC rules, this prospectus
does not contain all of the information we have included in the registration
statement and the accompanying exhibits and schedules we filed with the SEC. You
may refer to the registration statement, exhibits and schedules for more
information about us and our common stock. You can read and copy the
registration statement, exhibits and schedules at the SEC's Public Reference
Room at 450 Fifth Street, N.W., Washington, D.C. 20549 and at the SEC's regional
offices located at Seven World Trade Center, New York, New York 10048, and at
500 West Madison Street, Chicago, Illinois 60661. You can obtain information
about the operation of the SEC's Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC also maintains an Internet site that contains reports,
proxy and information statements, and other information regarding issuers that
file electronically with the SEC. The address of that site is
http://www.sec.gov.

Following this offering, we will be required to file current reports,
quarterly reports, annual reports, proxy statements and other information with
the SEC. You may read and copy those reports, proxy statement and other
information at the SEC's Public Reference Room and regional offices or through
its Internet site. We intend to furnish our stockholders with annual reports
that will include a description of our operations and audited consolidated
financial statements certified by an independent public accounting firm.

73
<PAGE> 77

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms commonly
used in the oil and natural gas industry and this prospectus:

BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.

BBL/D. One stock tank barrel of oil or other liquid hydrocarbons per day.

BCFE. One billion cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

COMPLETION. The installation of permanent equipment for the production of
oil or natural gas.

DELAY RENTALS. Fees paid to the owner of the oil and natural gas lease
prior to the commencement of production.

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 or in close proximity to an area of
known production targeting existing reservoirs.

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

FINDING AND DEVELOPMENT COSTS. Capital costs incurred in the acquisition,
exploration, development and revisions of proved oil and natural gas reserves
divided by proved reserve additions.

GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be,
in which we have a working interest.

HORIZONTAL DRILLING. A drilling operation in which a portion of the well is
drilled horizontally within a productive or potentially productive formation.
This operation usually yields a well which has the ability to produce higher
volumes than a vertical well drilled in the same formation.

INFILL DRILLING. A drilling operation in which one or more development
wells is drilled within the proven boundaries of a field between two or more
other wells.

INJECTOR WELL OR INJECTOR. A well which is used to place liquids or gases
into the producing zone during secondary/tertiary recovery operations to assist
in maintaining reservoir pressure and enhancing recoveries from the field.

MBBL. One thousand barrels of oil or other liquid hydrocarbons.

MCF. One thousand cubic feet of natural gas.

MCFE. One thousand cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

MMBBL. One million barrels of oil or other liquid hydrocarbons.

MMBTU. One million British thermal units. One British thermal unit is the
amount of heat required to raise the temperature of one pound of water one
degree Fahrenheit.

MMCF. One million cubic feet of natural gas.

MMCF/D. One million cubic feet of natural gas per day.

MMCFE. One million cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

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<PAGE> 78

MMCFE/D. One million cubic feet equivalent of natural gas per day,
calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of
oil.

NET ACRES OR NET WELLS. Gross acres or wells multiplied, as the case may
be, by the percentage working interest owned by us.

NET PRODUCTION. Production that is owned by Westport less royalties and
production due others.

NET UNRISKED RESERVES. Proved reserves which are owned by Westport, less
royalties.

NYMEX. New York Mercantile Exchange.

OIL. Crude oil or condensate.

OPERATING INCOME. Gross oil and natural gas revenue less applicable
production taxes and lease operating expense.

OPERATOR. The individual or company responsible for the exploration,
exploitation and production of an oil or natural gas well or lease.

PRESENT VALUE OF FUTURE NET REVENUES OR PRESENT VALUE OR PV10. The pretax
present value of estimated future revenues to be generated from the production
of proved reserves calculated in accordance with SEC guidelines, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and depreciation, depletion and amortization, and discounted using an
annual discount rate of 10%.

PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

PROVED RESERVES. The estimated quantities of 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. 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.

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

SALT DOME. A generally dome-shaped intrusion into sedimentary rock that has
a mass of salt as its core. The impermeable nature of the salt structure may act
as a mechanism to trap hydrocarbons migrating through surrounding rock
formations.

SPUDDED. To have begun actual drilling of a well.

2-D SEISMIC. The method by which a cross-section of the earth's subsurface
is created through the interpretation of reflecting seismic data collected along
a single source profile.

3-D SEISMIC. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of reflection seismic data
collected over a surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do conventional surveys and contribute
significantly to field appraisal, exploitation and production.

TCF. One trillion cubic feet of natural gas.

TERTIARY RECOVERY. An enhanced recovery operation that normally occurs
after waterflooding in which chemicals or gasses are used as the injectant.

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<PAGE> 79

WATERFLOOD. A secondary recovery operation in which water is injected into
the producing formation in order to maintain reservoir pressure and force oil
toward and into the producing wells.

WORKING INTEREST. An interest in an oil and natural gas lease that gives
the owner of the interest the right to drill for and produce oil and natural gas
on the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations.

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<PAGE> 80

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
WESTPORT OIL AND GAS COMPANY, INC.:
Report of Independent Public Accountants.................. F-2
Consolidated Balance Sheets as of December 31, 1998 and
1999................................................... F-3
Consolidated Statements of Operations for the years ended
December 31, 1997, 1998
and 1999............................................... F-4
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 1997, 1998 and 1999........... F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1998
and 1999............................................... F-6
Notes to Consolidated Financial Statements................ F-7
Consolidated Balance Sheet as of December 31, 1999 and
March 31, 2000......................................... F-19
Consolidated Statements of Operations for the three months
ended March 31, 1999 and 2000.......................... F-20
Consolidated Statement of Cash Flows for the three months
ended March 31, 1999 and 2000.......................... F-21
Notes to Consolidated Financial Statements................ F-22
EPGC PROPERTIES:
Report of Independent Public Accountants.................. F-24
Statements of Revenues and Direct Operating Expenses for
the EPGC
Properties for the years ended December 31, 1997, 1998
and 1999 and the three months ended March 31, 1999 and
2000................................................... F-25
Notes to Statements of Revenues and Direct Operating
Expenses for the EPGC Properties....................... F-26
</TABLE>

F-1
<PAGE> 81

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Westport Oil and Gas Company, Inc.:

We have audited the accompanying consolidated balance sheets of Westport
Oil and Gas Company, Inc. (a Delaware corporation) and subsidiaries as of
December 31, 1999 and 1998, and the related consolidated statements of
operations, stockholders' equity and cash flows for each of the three years in
the period ended December 31, 1999. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Westport Oil and Gas
Company, Inc. and subsidiaries as of December 31, 1999 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.

ARTHUR ANDERSEN LLP

Denver, Colorado
February 16, 2000.

F-2
<PAGE> 82

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1998 1999
-------- --------
(IN THOUSANDS,
EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS

Current Assets:
Cash and cash equivalents................................. $ 10,148 $ 19,475
Accounts receivable, net.................................. 8,197 14,645
Prepaid expenses.......................................... 1,306 1,712
-------- --------
Total current assets.............................. 19,651 35,832
-------- --------
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method:
Proved properties...................................... 316,243 307,068
Unproved properties.................................... 32,611 18,089
Office furniture and equipment............................ 2,165 2,182
Leasehold improvements.................................... 488 488
-------- --------
351,507 327,827
Less accumulated depletion, depreciation and amortization... (74,272) (92,950)
-------- --------
Net property and equipment........................ 277,235 234,877
-------- --------
Other assets................................................ 5,416 768
-------- --------
Total assets...................................... $302,302 $271,477
======== ========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable.......................................... $ 10,242 $ 8,482
Accrued expenses.......................................... 6,338 10,574
Ad valorem taxes payable.................................. 2,269 2,606
Current portion of long-term debt......................... 31,795 1,333
-------- --------
Total current liabilities......................... 50,644 22,995
-------- --------
Long-term debt.............................................. 121,333 105,462
Other liabilities........................................... 3,588 3,009
-------- --------
Total liabilities................................. 175,565 131,466
-------- --------
Commitments and contingencies (Note 8)
Stockholders' equity:
Common stock, $0.000333 par value; 12,000,000 and
10,000,000 shares authorized; 10,420,334 and 9,053,667
shares issued and outstanding at December 31, 1999 and
1998, respectively..................................... 3 3
Additional paid-in capital................................ 182,048 198,448
Accumulated deficit....................................... (55,314) (58,440)
-------- --------
Total stockholders' equity........................ 126,737 140,011
-------- --------
Total liabilities and stockholders' equity........ $302,302 $271,477
======== ========
</TABLE>

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

F-3
<PAGE> 83

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------
1997 1998 1999
----------- ----------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Operating revenues:
Oil and natural gas sales................................. $ 63,089 $ 51,505 $73,763
-------- -------- -------
Operating costs and expenses:
Lease operating expense................................... 19,583 21,554 22,916
Production taxes.......................................... 5,923 3,888 5,742
Exploration............................................... 7,424 14,664 7,314
Depletion, depreciation and amortization.................. 23,659 36,264 25,210
Impairment of proved properties........................... 5,765 8,794 3,072
Impairment of unproved properties......................... 380 1,898 2,273
General and administrative................................ 5,316 5,913 5,297
-------- -------- -------
Total operating expenses.......................... 68,050 92,975 71,824
-------- -------- -------
Operating income (loss)........................... (4,961) (41,470) 1,939
-------- -------- -------
Other income (expense):
Interest expense.......................................... (5,635) (8,323) (9,207)
Interest income........................................... 309 403 489
Gain (loss) on sale of assets, net........................ (13) -- 3,637
Other..................................................... (54) 29 16
-------- -------- -------
Loss before income taxes.................................... (10,354) (49,361) (3,126)
Benefit for income taxes.................................... 973 -- --
-------- -------- -------
Net loss.................................................... $ (9,381) $(49,361) $(3,126)
======== ======== =======
Weighted average number of common shares outstanding:
Basic and Diluted......................................... 6,217 7,336 9,818
======== ======== =======
Net loss per common share:
Basic and Diluted......................................... $ (1.51) $ (6.73) $ (0.32)
======== ======== =======
</TABLE>

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

F-4
<PAGE> 84

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
RETAINED
COMMON STOCK ADDITIONAL EARNINGS
--------------- PAID-IN (ACCUMU-
SHARES AMOUNT CAPITAL LATED DEFICIT) TOTAL
------ ------ ---------- -------------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996.............. 3,890 $ 1 $ 77,042 $ 3,428 $ 80,471
Purchase of common stock by Parent (Note
5)................................... 2,535 1 60,007 -- 60,008
Net loss................................ -- -- -- (9,381) (9,381)
------ --- -------- -------- --------
Balance at December 31, 1997.............. 6,425 2 137,049 (5,953) 131,098
Purchase of common stock by Parent (Note
5)................................... 2,629 1 44,999 -- 45,000
Net Loss................................ -- -- -- (49,361) (49,361)
------ --- -------- -------- --------
Balance at December 31, 1998.............. 9,054 3 182,048 (55,314) 126,737
Purchase of common stock by Parent (Note
5)................................... 1,366 -- 16,400 -- 16,400
Net loss................................ -- -- -- (3,126) (3,126)
------ --- -------- -------- --------
Balance at December 31, 1999.............. 10,420 $ 3 $198,448 $(58,440) $140,011
====== === ======== ======== ========
</TABLE>

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

F-5
<PAGE> 85

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
---------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss.................................................. $ (9,381) $(49,361) $(3,126)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depletion, depreciation and amortization............... 23,659 36,264 25,210
Exploration............................................ 3,677 12,323 5,863
Impairment of proved properties........................ 5,765 8,794 3,072
Impairment of unproved properties...................... 380 1,898 2,273
Loss (gain) on sale of assets.......................... 13 -- (3,637)
Deferred income taxes.................................. (915) -- --
Changes in assets and liabilities, net of effects of
acquisitions:
Decrease (increase) in accounts receivable........... (5,911) 11,778 (6,448)
Increase in prepaid expenses......................... (517) (119) (338)
Increase (decrease) in accounts payable.............. 8,048 (11,706) (1,753)
Increase (decrease) in ad valorem taxes payable...... 366 (1,097) 337
Increase in accrued expenses......................... 1,599 1,817 4,236
Decrease in income taxes payable to Parent........... (11) -- --
Decrease in other liabilities........................ (655) (133) (579)
--------- -------- -------
Net cash provided by operating activities................... 26,117 10,458 25,110
Cash flows from investing activities:
Additions to property and equipment....................... (48,754) (52,466) (17,836)
Proceeds from sales of assets............................. 3,186 299 31,994
Axem acquisition, net of cash acquired.................... (102,008) -- --
Acquisition of Axem EG LLC partnership interest........... (5,000) -- --
TMC acquisition, net of cash acquired..................... -- (56,348) --
Other acquisitions........................................ -- (7,030) --
Other..................................................... 164 (310) (8)
--------- -------- -------
Net cash provided by (used in) investing activities......... (152,412) (115,855) 14,150
--------- -------- -------
Cash flows from financing activities:
Purchase of common stock by Parent........................ 60,008 45,000 16,400
Proceeds from issuance of long-term debt.................. 68,000 61,000 --
Repayment of long-term debt............................... (1,333) (1,333) (46,333)
--------- -------- -------
Net cash provided by (used in) financing activities......... 126,675 104,667 (29,933)
--------- -------- -------
Net increase (decrease) in cash and cash equivalents........ 380 (730) 9,327
Cash and cash equivalents, beginning of year................ 10,498 10,878 10,148
--------- -------- -------
Cash and cash equivalents, end of year...................... $ 10,878 $ 10,148 $19,475
========= ======== =======
Supplemental cash flow information:
Cash paid for interest.................................... $ 4,429 $ 7,472 $ 9,575
========= ======== =======
Cash paid for income taxes................................ $ -- $ -- $ --
========= ======== =======
</TABLE>

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

F-6
<PAGE> 86

WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Westport Oil and Gas Company, Inc. (the "Company") was formed as a Delaware
corporation on July 5, 1991. As of December 31, 1999, the Company was a 99.6%
owned subsidiary of Westport Energy LLC ("Parent"). The remaining 0.4% was owned
by two executive officers of the Company. Business activities of the Company
include the exploration for and production of oil and natural gas primarily in
the Rocky Mountains, the Gulf Coast, the West Texas/Mid-Continent area and the
Gulf of Mexico.

A summary of the Company's significant accounting policies follows:

Cash and Cash Equivalents

For purposes of the statements of cash flows, the Company considers all
highly liquid investments purchased with an original maturity of three months or
less to be cash equivalents. The total carrying amount of cash and equivalents
approximates the fair value of such instruments.

Natural Gas Balancing

The Company uses the sales method of accounting for natural gas imbalances.
Under this method, revenue is recognized based on cash received rather than the
Company's proportionate share of natural gas produced. Natural gas imbalances at
December 31, 1998 and 1999 were not significant.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas operations using the
successful efforts method of accounting. Under this method, all costs associated
with property acquisition, successful exploratory wells and all development
wells are capitalized. Items charged to expense generally include geological and
geophysical costs, costs of unsuccessful exploratory wells and oil and natural
gas production costs. All of the Company's oil and natural gas properties are
located within the continental United States, the Gulf of Mexico and Canada.

The Company follows the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of." SFAS No. 121 requires the Company
to assess the need for an impairment of capitalized costs of oil and natural gas
properties on a field-by-field basis. In applying this statement, the Company
compares the expected undiscounted future net revenues on a field-by-field basis
with the related net capitalized costs at the end of each period. When the net
capitalized costs exceed the undiscounted future net revenues, the cost of the
property is written down to "fair value," which is determined using the
discounted future net revenues on a field-by-field basis. In 1997, 1998 and
1999, the Company recorded impairment expense of $5.8 million, $8.8 million and
$3.1 million, respectively.

Capitalized costs of proved properties are depleted on a field-by-field
basis using the units-of-production method based upon proved oil and natural gas
reserves.

Gains and losses resulting from the disposition of proved properties are
included in operations. In management's opinion abandonment, restoration and
dismantlement costs from onshore properties generally approximate the residual
value of equipment, and therefore, no accrual for such costs has been recorded.

Unproved properties are assessed periodically to determine whether
impairment has occurred. Sales proceeds from unproved oil and natural gas
properties are credited to related costs of the prospect sold until all such
costs are recovered and then to net gain or loss on sales of unproved oil and
natural gas properties. In 1997, 1998 and 1999, the Company recorded impairment
expense of $0.4 million, $1.9 million and $2.3 million, respectively.
F-7
<PAGE> 87
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Principles of Consolidation

The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries. All significant intercompany accounts and
transactions have been eliminated in the consolidation.

Earnings (Loss) per Common Share

The Company follows the provisions of SFAS No. 128, "Earnings Per Share."
Basic earnings per share is computed based on the weighted average number of
common shares outstanding. Diluted earnings per share is computed based on the
weighted average number of common shares outstanding adjusted for the
incremental shares attributed to outstanding options and warrants to purchase
common stock. All options and warrants to purchase common shares were excluded
from the computation of diluted earnings per share in 1997, 1998 and 1999,
because they were antidilutive as a result of the Company's net losses in those
years.

Income Taxes

The Company computes income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes." SFAS No. 109 requires an asset and liability
approach which results in the recognition of deferred tax liabilities and assets
for the expected future tax consequences of temporary differences between the
carrying amounts and the tax bases of those assets and liabilities. SFAS No. 109
also requires the recording of a valuation allowance if it is more likely than
not that some portion or all of a deferred tax asset will not be realized.

The Company has an informal tax sharing agreement with the Parent whereby
income tax liabilities are calculated as if the Company was a separate taxable
entity. Pursuant to this tax sharing agreement, payables and receivables with
the Parent resulting from the calculation are recorded and settled accordingly.

Office Furniture and Equipment and Leasehold Improvements

Office furniture and equipment are stated at cost and are depreciated using
the straight-line method over their estimated useful lives of five to seven
years. Leasehold improvements are amortized over the life of the related lease.
Maintenance and repairs are charged to expense as incurred. Gains or losses on
dispositions of office furniture and equipment are included in operations.

Hedging Activity

The Company periodically enters into commodity derivative contracts and
fixed-price physical contracts to manage its exposure to oil and natural gas
price volatility. The Company primarily utilizes price swaps which are generally
placed with major financial institutions or with counterparties of high credit
quality that the Company believes are minimal credit risks. The oil and natural
gas reference prices of these commodity derivatives contracts are based upon
crude oil and natural gas futures which have a high degree of historical
correlation with actual prices received by the Company. The Company accounts for
its commodity derivatives contracts using the hedge (deferral) method of
accounting. Under this method, realized gains and losses from the Company's
price risk management activities are recognized in oil and natural gas revenue
when the associated production occurs, and the resulting cash flows are reported
as cash flows from operating activities. Gains and losses from commodity
derivatives contracts that are closed before the hedged production occurs are
deferred until the production month originally hedged. In the event of a loss of
correlation between changes in oil and natural gas reference prices under a
commodity derivatives contract and actual oil and natural gas prices, a gain or
loss would be recognized

F-8
<PAGE> 88
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

currently to the extent the commodity derivatives contract did not offset
changes in actual oil and natural gas prices.

At December 31, 1999, the Company had energy price swap agreements for a
total of 4,400,000 Mmbtus for the months of April through December, 2000 at a
fixed price of $2.52 per Mmbtu. Also, at December 31, 1999, the Company had
energy price swap agreements for a total of 2,012,000 barrels for the months of
January through December, 2000 at a floor price ranging from $18.25 per barrel
to $20.50 per barrel and a ceiling price ranging from $20.62 per barrel to
$24.30 per barrel.

In accordance with SFAS No. 107, "Disclosures About Fair Value of Financial
Instruments," the Company has estimated the fair value of its hedging
arrangements at December 31, 1999 utilizing the then-applicable crude oil and
natural gas strips. While it is not the Company's intention to terminate any of
the arrangements, it is estimated that the Company would have to pay
approximately $801,000 to terminate the then-existing arrangements on December
31, 1999. Due to the volatility of crude oil and natural gas prices, the fair
market value may not be representative of the actual gain or loss that will be
realized by the Company in 2000.

The Company recognized a loss of $7.9 million from hedging agreements in
1999. The Company recognized gains from oil hedging agreements of $298,000 in
1998 and $47,000 in 1997.

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for all fiscal quarters of fiscal years beginning after June
15, 2000. The Company has not yet quantified the impacts of adopting SFAS No.
133 on its financial statements and has not determined the timing of, or method
of, adoption of SFAS No. 133. However, SFAS No. 133 could increase volatility in
earnings.

Interest Rate Swap Agreement

The Company periodically enters into interest rate swap agreements to
effectively convert a portion of its floating-rate borrowings into fixed rate
obligations. The interest rate differential to be received or paid is recognized
as a current period adjustment to interest expense.

Fair Value of Financial Instruments

The carrying amounts of the Company's cash, accounts receivable, accounts
payable, and accrued expenses approximate fair value due to the short-term
maturities of these assets and liabilities. The carrying amount of the Company's
long-term debt approximates fair value based on the variable borrowing rate of
the credit facility.

Use of Estimates

The preparation of consolidated 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 consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
F-9
<PAGE> 89
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company's consolidated financial statements are based on a number of
significant estimates including oil and natural gas reserve quantities which are
the basis for the calculation of depletion and impairment of oil and natural gas
properties. The Company's reserve estimates, which are inherently imprecise, are
determined by outside petroleum engineers.

Reclassifications

Certain amounts reported in the prior year consolidated financial
statements have been reclassified to correspond to the December 31, 1999
presentation.

2. CONCENTRATION OF CREDIT RISK:

The Company has accounts with separate banks in Denver, Colorado, New York
City, New York and Calgary, Canada. The Company invests substantially all
available cash in an overnight investment account consisting of U.S. Treasury
obligations. At December 31, 1999, the balance in the overnight investment
account was $15.7 million.

The Company sells its oil and natural gas production to creditworthy
companies. Allowances for potential credit losses relating to product sales are
not maintained and the Company does not require collateral.

3. INCOME TAXES:

The components of the provision (benefit) for income taxes are as follows:

<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31,
-------------------
1997 1998 1999
----- ---- ----
(IN THOUSANDS)
<S> <C> <C> <C>
Current
Federal (due to/from Parent).............................. $(100) $ -- $ --
State..................................................... 42 -- --
----- ---- ----
(58) -- --
----- ---- ----
Deferred
Federal................................................... (865) -- --
State..................................................... (50) -- --
----- ---- ----
(915) -- --
----- ---- ----
Provision (benefit) for income taxes........................ $(973) $ -- $ --
===== ==== ====
</TABLE>

The difference between the provision (benefit) for income taxes and the
amounts computed by applying the U.S. Federal statutory rate are as follows:

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
1997 1998 1999
-------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Federal statutory rate of 34%.......................... $(3,520) $(16,783) $(1,063)
State income taxes, net of Federal effect.............. (229) (1,630) (103)
Change in valuation allowance.......................... 2,786 18,425 1,177
Other permanent differences............................ (10) (12) (11)
------- -------- -------
$ (973) $ -- $ --
======= ======== =======
</TABLE>

F-10
<PAGE> 90
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Long-term deferred tax assets are comprised of the following:

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax asset:
Oil and natural gas properties............................ $ 5,171 $ 4,945
Net operating loss carryforward........................... 16,040 17,443
-------- --------
21,211 22,388
Valuation allowance......................................... (21,211) (22,388)
-------- --------
Net deferred tax asset...................................... $ -- $ --
======== ========
</TABLE>

As of December 31, 1999, the Company had net operating loss carryforwards
for income tax purposes of approximately $46.8 million which expire between 2017
and 2019 and may be utilized to reduce future tax liability of the Company.

4. LONG-TERM DEBT:

Long-term debt consisted of:

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
9% bank term note, payable in 24 equal quarterly
installments of $333,333 plus interest, January 31, 1995
through December 31, 2000................................. $ 2,667 $ 1,333
Bank line of credit due on December 31, 2003................ 150,461 105,462
-------- --------
153,128 106,795
Less current portion........................................ (31,795) (1,333)
-------- --------
$121,333 $105,462
======== ========
</TABLE>

On December 31, 1996, the Company entered into a credit agreement ("Credit
Agreement") with a bank. Borrowings under the Credit Agreement are secured by
substantially all of the Company's oil and natural gas properties. On November
12, 1999 the Credit Agreement was amended resulting in a borrowing base of
$120,000,000. The borrowing base is subject to redetermination every six months
with the next evaluation date being April 1, 2000. The entire unpaid principal
balance and accrued interest is due on December 31, 2003. The Company can elect
from time to time to classify all or any portion of the outstanding balance as a
tranche, which refers to a set of fixed rate portions with identical interest
periods. There shall be no more than six tranches in effect at any time. The
Company must comply with certain covenants, including limitations on additional
indebtedness, restriction on the payment of dividends and a requirement to
maintain a current ratio of no less than 1 to 1. Calculation of current ratio
excludes current portion of long-term debt and includes up to $10 million of
available borrowings.

The Credit Agreement bears interest at the London Interbank borrowing rate
plus a margin which fluctuates from 1% to 1.75% based on borrowing base
utilization. The weighted average rate in effect was 7.01% and 7.61% at December
31, 1998 and 1999, respectively.

Commitment fees under the Credit Agreement fluctuate from 0.25% to 0.50%
based on the ratio of the borrowing base to available borrowings.

The 9% bank term note relates to a master credit facility under which the
bank may lend the Company up to $35 million. The outstanding principal amount of
the loan is without collateral. The

F-11
<PAGE> 91
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

master credit facility contains covenants which, among other things, include
reporting requirements and maintenance of insurance. It is the Company's intent
to retire this note pursuant to its terms.

The Company entered into interest rate swap contracts for a period
commencing on July 30, 1998 and ending on March 11, 2002. The contracts, as
amended, are for an aggregate notional amount of $50 million with fixed interest
rates between 5.58% and 5.61% payable by the Company and the variable interest
rate, a three-month LIBOR, payable by the third party. The difference between
the Company's fixed rates and the three-month LIBOR rate, which is reset every
90 days, is received or paid by the Company in arrears every 90 days and
recognized as an adjustment to interest expense. Accordingly, the Company paid
$192,000 in 1999 and received $7,000 in December, 1998. The unrecognized gain on
this contract totaled $720,000 based on December 31, 1999 market values.

Maturities of long-term debt for each of the five years following December
31, 1999 are as follows: (in thousands)

<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
------------------------
<S> <C>
2000...................................................... $ 1,333
2001...................................................... --
2002...................................................... --
2003...................................................... 105,462
2004...................................................... --
--------
$106,795
========
</TABLE>

5. STOCKHOLDERS' EQUITY:

In 1997, 1998 and 1999, 2,534,854, 2,628,505, and 1,366,667 common shares
were purchased by the Parent for per share prices of $23.67, $17.12, and $12.00,
respectively. The share prices reflected the estimated market value of the
Company's stock at the time of purchase.

6. STOCK OPTIONS:

On June 1, 1996, the Company established the Westport Oil and Gas Company,
Inc. Stock Option Plan (the "Stock Option Plan") for certain key employees of
the Company. The Company initially reserved 435,000 shares of common stock for
issuance under the Stock Option Plan. In no event will the sum of the number of
shares issued under the Stock Option Plan exceed 15% of the outstanding stock of
the Company. During 1997, 1998 and 1999, 267,315, 56,500 and 392,400,
respectively, shares of the Company's common stock were granted under the Stock
Option Plan at exercise prices between $12.00 and $23.67 per share, which
approximated the estimated fair market value of the shares at the date of grant.
The vesting periods for these options vary from four to five years, and the
options are exercisable for a period of 10 years after the date of grant.

On November 4, 1996, the Company adopted the Westport Oil and Gas Company,
Inc. Directors' Stock Option Plan (the "Directors' Stock Option Plan") for
nonemployee directors. The Company has reserved 27,000 shares of common stock
for issuance under the Directors' Stock Option Plan. During 1997, 1998 and 1999,
6,000 shares, of the Company's common stock were granted under the Directors'
Stock Option Plan at exercise prices of between $12.00 and $23.67 per share,
which approximated the estimated fair market value of the shares at the date of
grant. These options are fully vested and immediately exercisable upon date of
grant. The options terminate 10 years after the date of grant. No options were
exercised during the years ended December 31, 1997, 1998 and 1999.

On April 1, 1999, the Company cancelled options to purchase 222,375 shares
of the Company's common stock and reduced the exercise price of options to
purchase 497,940 shares of the Company's

F-12
<PAGE> 92
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

common stock from $23.05 per share to $12.00 per share, the estimated fair value
of the shares on that day. In addition, on April 1, 1999, the Company granted
options to purchase an additional 302,500 shares of the Company's common stock
at an exercise price of $12.00 per share.

On March 31, 1999, the Financial Accounting Standards Board issued an
exposure draft, "Accounting for Certain Transactions involving Stock
Compensation -- an interpretation of APB Opinion No. 25" (the "Interpretation").
If enacted in its current form, the Interpretation would require the Company to
account for the 497,940 repriced options discussed above (plus 216,317 of the
additional options granted on April 1, 1999 and deemed to have replaced the
cancelled options) as variable awards through the date of exercise of the
options. Consequently, the final measurement of compensation cost related to the
repriced options will not be determinable until the date of exercise. The
provisions of the final Interpretation will be applied prospectively from June
30, 2000 (the proposed effective date of the final Interpretation). As a result,
on July 1, 2000, the Company will prospectively apply variable award accounting,
recording any increase in the Company's stock price above the estimated fair
value of the stock on July 1, 2000 as compensation cost.

A summary of the status of the Company's Stock Option Plans as of December
31, 1997, 1998 and 1999 and changes during the years ended December 31, 1997,
1998 and 1999 are as follows:

<TABLE>
<CAPTION>
NUMBER OF SHARES
--------------------------------
DIRECTORS' WEIGHTED
STOCK STOCK AVERAGE
OPTION OPTION EXERCISE
PLAN PLAN PRICE
-------- ---------- --------
<S> <C> <C> <C>
Balance at December 31, 1996........................... 382,500 2,000 $23.67
Options granted...................................... 267,315 6,000 23.52
-------- ------
Balance at December 31, 1997........................... 649,815 8,000 23.61
Options granted...................................... 56,500 6,000 17.12
-------- ------
Balance at December 31, 1998........................... 706,315 14,000 23.05
Options cancelled.................................... (218,732) (3,643) 23.05
Options granted...................................... 392,400 6,000 12.96
-------- ------
Balance at December 31, 1999........................... 879,983 16,357 12.43
======== ======
Options exercisable at December 31, 1997............... 93,000 8,000 23.61
======== ======
Options exercisable at December 31, 1998............... 251,079 14,000 23.47
======== ======
Options exercisable at December 31, 1999............... 287,339 16,357 12.00
======== ======
</TABLE>

F-13
<PAGE> 93
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company has elected to continue following Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," and has elected to
adopt the disclosure provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation." Had compensation costs for the Company's options been determined
based on the fair value at the grant dates consistent with SFAS No. 123, the
Company's net loss would have been increased to the pro forma amounts indicated
below:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1998 1999
------- -------- -------
<S> <C> <C> <C>
Net loss............................................... $(9,381) $(49,361) $(3,126)
As reported.......................................... (9,981) (50,385) (4,114)
Pro forma............................................
Basic and diluted net loss per common share
As reported.......................................... $ (1.51) $ (6.73) $ (0.32)
Pro forma............................................ (1.61) (6.87) (0.42)
</TABLE>

The weighted average fair value of options granted during the years ended
December 31, 1997, 1998 and 1999 as calculated using the Black-Scholes option
pricing model was $5.83, $4.03 and $6.32, respectively. The fair value of each
option granted is estimated with the following weighted-average assumptions for
grants in 1997, 1998 and 1999: risk-free interest rate of 6.13%, 5.52% and
5.53%, respectively; no dividend yields; expected volatility of 0.01%; and
expected lives of 5 years.

7. MAJOR PURCHASERS:

The following purchasers accounted for 10% or more of the Company's oil and
natural gas sales for the years ended December 31, 1997, 1998 and 1999:

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
<S> <C> <C> <C>
Conoco Inc. ................................................ 39% 26% 26%
Koch Oil Company............................................ 22% 18% --
Energen Resources MAQ, Inc. ................................ -- 17% 20%
EOTT Energy Corporation..................................... -- -- 20%
</TABLE>

8. COMMITMENTS AND CONTINGENCIES:

At December 31, 1999, the Company had two leases covering office space
under noncancelable agreements which begin to expire in February, 2002. The
minimum annual rental payments under the leases are as follows:

<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
------------------------ (IN THOUSANDS)
<S> <C>
2000................................................... $ 521
2001................................................... 534
2002................................................... 463
2003................................................... 420
------
$1,938
======
</TABLE>

Rent expense for the years ended December 31, 1997, 1998 and 1999 was
approximately $516,000, $652,000 and $497,000, respectively.

The Company is subject to governmental and regulatory controls arising in
the ordinary course of business. It is the opinion of the Company's management
that there are no claims or litigation involving the Company that are likely to
have a material adverse effect on its financial position or results of
operations.

F-14
<PAGE> 94
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

9. PRODUCING PROPERTIES ACQUISITIONS AND DIVESTITURES:

Total Minatome Corporation Acquisition

On October 15, 1998, the Company entered into an agreement ("Agreement")
with an industry partner ("Purchaser") in connection with a stock purchase
("Stock Purchase") agreement between Purchaser and Total Minatome Corporation
("TMC") for the purchase of all of the outstanding stock of TMC ("TMC
Acquisition"), as an express third party beneficiary of the rights of the
Purchaser and the obligations of TMC under the Stock Purchase. Pursuant to the
Agreement, the Company acquired an undivided 31% interest in the total assets of
TMC for a cash purchase price of approximately $56 million. The TMC Acquisition
was funded by sales of common stock to the Company's Parent and borrowings under
the Credit Agreement. The TMC Acquisition was accounted for using the purchase
method with the purchase price allocated among proved and unproved oil and
natural gas properties and other assets and liabilities based on their relative
fair values. Revenue associated with the TMC Acquisition for the 3-month period
ended December 31, 1998 was approximately $5.5 million.

Other Acquisitions

During the year ended 1998 the Company acquired producing properties
("Other Acquisitions") for a total cash purchase price of approximately $7
million. The Other Acquisitions were funded by sales of common stock to the
Company's Parent and borrowings under the Credit Agreement. The Other
Acquisitions were accounted for using the purchase method. Revenues associated
with these properties for the year ended December 31, 1998 were approximately
$1.3 million.

Sale of Offshore Properties

During 1999, the Company sold certain interests in oil and natural gas
development and exploration prospects located offshore in the Gulf of Mexico for
$21.4 million. The properties had a book value of $17.4 million, and a $4.0
million gain was recorded on the sale. Proceeds from the sale were used to
reduce the borrowings under the Credit Agreement.

10. RETIREMENT SAVINGS PLAN:

Effective December 1, 1995, the Company adopted a retirement savings plan.
The Westport Savings and Profit Sharing Plan (the "Plan") is a defined
contribution plan and covers all employees of the Company. The Plan is subject
to the provisions of the Employee Retirement Income Security Act of 1974, as
amended, and Section 401(k) of the Internal Revenue Code.

The assets of the Plan are held and the related investments are executed by
the Plan's trustee. Participants in the Plan have investment alternatives in
which to place their funds and may place their funds in one or more of these
investment alternatives. Administrative fees are paid by the Company on behalf
of the Plan. The Plan provides for discretionary matching by the Company of 50%
of each participant's contributions up to 6% of the participant's compensation.
The Company contributed $78,000, $104,000 and $114,000, for the years ended
December 31, 1997, 1998, and 1999, respectively.

11. SUBSEQUENT EVENTS:

The Company is currently in negotiations with a third party for the
acquisition of an oil and natural gas subsidiary of the third party. The
subsidiary's assets consist of oil and natural gas properties primarily located
offshore in the Gulf of Mexico. The anticipated purchase price will be composed
of a combination of the Company's common stock and assumption of debt. The
Company anticipates being the acquiror and accounting for the transaction using
purchase accounting. The Company anticipates closing the acquisition during
early 2000.

F-15
<PAGE> 95
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

12. SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS ACTIVITIES:

The following tables set forth certain historical costs and costs incurred
related to the Company's oil and natural gas producing activities:

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1997 1998 1999
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Capitalized costs
Proved oil and natural gas properties................ $234,836 $316,243 $307,068
Unproved oil and natural gas properties.............. 18,541 32,611 18,089
-------- -------- --------
Total oil and natural gas properties......... 253,377 348,854 325,157
Less: Accumulated depletion, depreciation and
amortization...................................... (38,599) (73,096) (91,325)
-------- -------- --------
Net capitalized costs........................ $214,778 $275,758 $233,832
======== ======== ========
</TABLE>

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
1997 1998 1999
--------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Costs incurred
Proved property acquisition costs..................... $ 98,768 $ 61,938 $ --
Unproved property acquisition costs................... 17,727 15,873 2,336
Exploration costs..................................... 13,269 22,642 11,789
Development costs..................................... 19,991 15,164 3,695
-------- -------- -------
Total......................................... $149,755 $115,617 $17,820
======== ======== =======
</TABLE>

Oil and Natural Gas Reserve Information (Unaudited)

The following summarizes the policies used by the Company in preparing the
accompanying oil and natural gas reserve disclosures, Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves and
reconciliation of such Standardized Measure between years.

Estimates of total proved and proved developed reserves at December 31,
1997, 1998 and 1999 were prepared by Ryder Scott Company L.P. 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 recovered
through existing wells with existing equipment and operating methods.
Substantially all of the Company's oil and natural gas reserves are located in
the United States and the Gulf of Mexico.

The Standardized Measure of discounted future net cash flows from
production of proved reserves was developed as follows:

1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end
economic conditions.

2. The estimated future cash flows from proved reserves were
determined based on year-end prices held constant, except in those
instances where fixed and determinable price escalations are included in
existing contracts.

3. The future cash flows are reduced by estimated production costs and
costs to develop and produce the proved reserves, all based on year-end
economic conditions and by the estimated effect of

F-16
<PAGE> 96
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

future income taxes based on the then-enacted tax law, the Company's tax
basis in its proved oil and natural gas properties and the effect of net
operating loss, investment tax credit and other carryforwards.

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

Quantities of Oil and Natural Gas Reserves (Unaudited)

The following table presents estimates of the Company's net proved and
proved developed oil and natural gas reserves:

<TABLE>
<CAPTION>
OIL(BBLS) GAS(MCF)
--------- --------
(IN THOUSANDS)
<S> <C> <C>
Proved reserves at December 31, 1996..................... 20,689 12,587
Revisions of previous estimates........................ (3,637) (1,779)
Discoveries............................................ 3,789 2,377
Purchase of minerals in place.......................... 10,264 20,871
Production............................................. (3,114) (5,265)
------ -------
Proved reserves at December 31, 1997..................... 27,991 28,791
Revisions of previous estimates........................ (2,905) 5,618
Discoveries............................................ 1,882 5,116
Purchase of minerals in place.......................... 1,212 70,395
Sales of minerals in place............................. (321) (1,235)
Production............................................. (3,483) (8,101)
------ -------
Proved reserves at December 31, 1998..................... 24,376 100,584
Revisions of previous estimates........................ 13,814 20,332
Discoveries............................................ 708 24,250
Purchase of minerals in place.......................... -- --
Sales of minerals in place............................. (2,848) (12,515)
Production............................................. (3,300) (13,313)
------ -------
Proved reserves at December 31, 1999..................... 32,750 119,338
====== =======
Proved developed reserves at December 31, 1997........... 25,588 26,866
====== =======
Proved developed reserves at December 31, 1998........... 20,323 80,627
====== =======
Proved developed reserves at December 31, 1999........... 29,489 82,807
====== =======
</TABLE>

F-17
<PAGE> 97
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Natural Gas Reserves (Unaudited)

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash flows................................. $ 487,298 $ 392,158 $ 986,992
Future production costs........................... (227,120) (170,279) (362,648)
Future development costs.......................... (16,528) (42,957) (44,552)
--------- --------- ---------
Future net cash flows before tax.................. 243,650 178,922 579,792
Future income taxes............................... (15,720) (4,766) (100,178)
--------- --------- ---------
Future net cash flows after tax................... 227,930 174,156 479,614
Annual discount at 10%............................ (74,380) (69,550) (157,179)
--------- --------- ---------
Standardized measure of discounted future net cash
flows........................................... $ 153,550 $ 104,606 $ 322,435
========= ========= =========
Discounted future net cash flows before income
taxes........................................... $ 155,408 $ 111,284 $ 349,099
========= ========= =========
</TABLE>

Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)

<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and natural gas sales, net of production costs... $(37,537) $(25,765) $(53,009)
Net changes in anticipated prices and production
cost............................................... (78,868) (65,975) 147,678
Extensions and discoveries, less related costs....... 17,911 6,536 19,831
Changes in estimated future development costs........ (1,260) 5,114 (11,691)
Previously estimated development costs incurred...... 538 6,865 6,175
Net change in income taxes........................... 21,518 (4,821) (19,985)
Purchase of minerals in place........................ 95,997 41,513 --
Sales of minerals in place........................... -- (2,301) (2,896)
Accretion of discount................................ 15,756 15,541 11,129
Revision of quantity estimates....................... (11,902) (5,822) 130,750
Changes in production rates and other................ (2,790) (19,829) (10,153)
-------- -------- --------
Change in standardized measure............. $ 19,363 $(48,944) $217,829
======== ======== ========
</TABLE>

F-18
<PAGE> 98

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1999 2000
-------------- -------------
(UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS

Current Assets:
Cash and cash equivalents................................. $ 19,475 $ 12,238
Accounts receivable -- net................................ 14,645 16,094
Prepaid expenses.......................................... 1,712 1,258
-------- --------
Total current assets.............................. 35,832 29,590
-------- --------
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method:
Proved properties...................................... 307,068 316,684
Unproved properties.................................... 18,089 18,749
Office furniture and equipment............................ 2,182 2,234
Leasehold improvements.................................... 488 489
-------- --------
327,827 338,156
Less accumulated depletion, depreciation and amortization... 92,950 99,070
-------- --------
Net property and equipment........................ 234,877 239,086
-------- --------
Other assets................................................ 768 827
-------- --------
Total assets...................................... $271,477 $269,503
======== ========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable.......................................... $ 8,482 $ 11,715
Accrued expenses.......................................... 10,574 3,990
Ad valorem taxes payable.................................. 2,606 3,328
Current portion of long-term debt......................... 1,333 1,000
-------- --------
Total current liabilities......................... 22,995 20,033
-------- --------
Long-term debt.............................................. 105,462 105,462
Other liabilities........................................... 3,009 2,600
-------- --------
Total liabilities................................. 131,466 128,095
-------- --------
Stockholders' equity:
Common stock, $0.000333 par value; 12,000,000 shares
authorized; 10,420,334 shares issued and outstanding at
December 31, 1999 and March 31, 2000, respectively..... 3 3
Additional paid-in capital................................ 198,448 198,448
Accumulated retained deficit.............................. (58,440) (57,043)
-------- --------
Total stockholders' equity........................ 140,011 141,408
-------- --------
Total liabilities and stockholders' equity........ $271,477 $269,503
======== ========
</TABLE>

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

F-19
<PAGE> 99

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE THREE MONTHS
ENDED MARCH 31,
---------------------
1999 2000
--------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Operating revenues:
Oil and natural gas sales................................. $14,978 $24,985
Operating costs and expenses:
Lease operating expense................................... 5,620 6,623
Production taxes.......................................... 798 2,268
Exploration............................................... 1,038 1,871
Depletion, depreciation and amortization.................. 8,489 6,172
Impairment of unproved properties......................... -- 235
General and administrative................................ 1,580 4,547
------- -------
Total operating expenses.......................... 17,525 21,716
------- -------
Operating income (loss)........................... (2,547) 3,269
------- -------
Other income (expense):
Interest expense.......................................... (2,497) (2,047)
Interest income........................................... 99 193
Gain (loss) on sale of assets -- net...................... 4,770 (17)
Other..................................................... 16 (1)
------- -------
2,388 (1,872)
------- -------
Income (loss) before income taxes........................... (159) 1,397
Benefit (provision) for income taxes........................ -- --
------- -------
Net income (loss)........................................... $ (159) $ 1,397
======= =======
Weighted average number of common shares outstanding:
Basic..................................................... 9,054 10,420
======= =======
Diluted................................................... 9,054 10,616
======= =======
Net income (loss) per common share:
Basic..................................................... $ (0.02) $ 0.13
======= =======
Diluted................................................... $ (0.02) $ 0.13
======= =======
</TABLE>

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

F-20
<PAGE> 100

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE THREE MONTHS
ENDED MARCH 31,
---------------------
1999 2000
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Cash flows from operating activities
Net income (loss)......................................... $ (159) $ 1,397
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depletion, depreciation and amortization............... 8,489 6,172
Exploration............................................ 727 1,424
Impairment of unproved properties...................... -- 235
Loss (gain) on sale of assets.......................... (4,770) 17
Changes in assets and liabilities:
Increase in accounts receivable...................... (2,410) (1,448)
Decrease in prepaid expenses......................... 26 454
Increase in accounts payable......................... 51 3,234
Increase in ad valorem taxes payable................. 272 722
Decrease in accrued expenses......................... (1,201) (6,798)
Decrease in other liabilities........................ (130) (194)
-------- --------
Net cash provided by operating activities................... 895 5,215
-------- --------
Cash flows from investing activities:
Additions to property and equipment....................... (333) (10,655)
Proceeds from sale of assets.............................. 23,245 50
Other acquisitions........................................ 385 (1,455)
Other assets.............................................. 28 (59)
-------- --------
Net cash provided by (used in) investing activities......... 23,325 (12,119)
-------- --------
Cash flows from financing activities:
Repayment of long-term debt............................... (14,333) (333)
-------- --------
Net cash used in financing activities....................... (14,333) (333)
-------- --------
Net increase (decrease) in cash and cash equivalents........ 9,887 (7,237)
Cash and cash equivalents at beginning of period............ 10,148 19,475
-------- --------
Cash and cash equivalents at end of period.................. $ 20,035 $ 12,238
======== ========
Supplemental cash flow information:
Cash paid for interest.................................... $ 2,820 $ 2,053
======== ========
Cash paid for income taxes................................ $ -- $ --
======== ========
</TABLE>

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

F-21
<PAGE> 101

WESTPORT OIL AND GAS COMPANY, INC.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. ORGANIZATION AND NATURE OF BUSINESS

Westport Oil and Gas Company, Inc. (the "Company") was formed as a Delaware
corporation on July 5, 1991. The Company is a 99.6% owned subsidiary of Westport
Energy LLC ("Parent"). The remaining 0.4% is owned by two executive officers of
the Company. Business activities of the Company include the exploration for and
production of oil and natural gas primarily in the Rocky Mountains, the Gulf
Coast, the West Texas/Mid Continent area and the Gulf of Mexico.

2. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated
financial statements contain all adjustments (consisting only of normal
recurring items) necessary to present fairly the financial position of the
Company as of March 31, 2000 and the results of operations and cash flows for
the periods presented. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to the Securities
and Exchange Commission's rules and regulations. The results of operations for
the periods presented are not necessarily indicative of the results to be
expected for the full year. Management believes the disclosures made are
adequate to ensure that the information is not misleading, and suggests that
these financial statements be read in conjunction with the Company's December
31, 1999 audited financial statements.

3. STOCK OPTION REPURCHASE

On March 24, 2000, the Company repurchased and cancelled 896,340 stock
options, representing all outstanding stock options, from employees and
directors for approximately $3.4 million. The cost to repurchase the stock
options is included in general and administrative expense in the accompanying
statement of operations for the three months ended March 31, 2000. The cost to
repurchase the stock options was based on the difference between $16.28 and the
exercise prices of $12.00 and $16.00 of such options. See Note 4.

4. SUBSEQUENT EVENTS

Merger

On April 7, 2000, Westport Oil and Gas merged with Equitable Production
(Gulf) Company ("EPGC"), an indirect subsidiary of Equitable Resources, Inc.
formed to hold certain Gulf of Mexico oil and natural gas properties (the "EPGC
Properties"). This transaction was effected by a merger between a newly-formed
subsidiary of EPGC and Westport Oil and Gas, resulting in Westport Oil and Gas
becoming a wholly-owned subsidiary of EPGC, which subsequently changed its name
to Westport Resources Corporation. The merger was accounted for using purchase
accounting with Westport Oil and Gas as the surviving entity. Westport Resources
Corporation paid $50 million in cash, issued 10.157 million shares of common
stock valued at $16.28 per share and assumed liabilities of $1.85 million to
consummate the merger. The EPGC properties consist of 37 producing properties
and 30 undeveloped blocks in the Gulf of Mexico.

Stock Option Grants

On May 8, 2000, Westport granted options to purchase 1,032,109 shares of
common stock to certain employees and directors at an exercise price of $16.28
per share. The options vest ratably over three years from the date of grant and
have a term of 10 years. Of the 1,032,109 options granted, 896,340 options are

F-22
<PAGE> 102
WESTPORT OIL AND GAS COMPANY, INC.

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)

deemed to be replacement options (the "Replacement Options") for those options
repurchased by the Company on March 24, 2000. See Note 3.

The 317,852 options not considered to be Variable Options will not be
subject to variable award accounting.

F-23
<PAGE> 103

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Westport Resources Corporation:

We have audited the accompanying statements of revenues and direct
operating expenses for the oil and natural gas properties of Equitable
Production (Gulf) Company (the "EPGC Properties") for each of the three years in
the period ended December 31, 1999. These statements are the responsibility of
EPGC's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

The statements of revenues and direct operating expenses for the EPGC
Properties were prepared for the purpose of complying with the rules and
regulations of the Securities and Exchange Commission as described in Note 1,
and are not intended to be a complete presentation of revenues and expenses.

In our opinion, the statements referred to above present fairly, in all
material respects, the revenues and direct operating expenses for the EPGC
Properties for each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Denver, Colorado
June 15, 2000.

F-24
<PAGE> 104

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE EPGC PROPERTIES
(IN THOUSANDS)

<TABLE>
<CAPTION>
FOR THE THREE MONTHS
FOR THE YEAR ENDED DECEMBER 31, ENDED MARCH 31,
--------------------------------- ---------------------
1997 1998 1999 1999 2000
--------- --------- --------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Oil and natural gas revenue.................. $33,881 $45,803 $64,872 $10,113 $18,932
Direct operating expenses.................... 5,503 10,030 7,215 1,671 1,215
------- ------- ------- ------- -------
Revenues in excess of direct operating
expenses................................... $28,378 $35,773 $57,657 $ 8,442 $17,717
======= ======= ======= ======= =======
</TABLE>

The accompanying notes are an integral part of these statements.

F-25
<PAGE> 105

NOTES TO STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES FOR
THE EPGC PROPERTIES
1. BASIS OF PRESENTATION:

On April 7, 2000, Westport Oil and Gas Company, Inc. ("Westport Oil and
Gas") merged with Equitable Production (Gulf) Company ("EPGC"). The transaction
was effected by a merger between a newly-formed subsidiary of EPGC and Westport
Oil and Gas, resulting in Westport Oil and Gas becoming a wholly-owned
subsidiary of EPGC, which subsequently changed its name to Westport Resources
Corporation. The merger had an October 1, 1999 effective date. EPGC was an
indirect subsidiary of Equitable Resources, Inc. formed to hold interests in
certain Gulf of Mexico oil and natural gas properties (the "EPGC Properties"),
including 37 producing properties and 30 undeveloped blocks. The merger was
accounted for using purchase accounting with Westport Oil and Gas as the
surviving entity.

The accompanying statements of revenues and direct operating expenses were
derived from the historical accounting records of the EPGC Properties. The
statements do not include depreciation, depletion and amortization, general and
administrative expenses, income taxes or interest expense as these costs may not
be comparable to the expenses expected to be incurred by the combined company.

2. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED):

Supplemental oil and natural gas reserve information related to the EPGC
Properties is reported in compliance with FASB Statement No. 69, "Disclosures
about Oil and Gas Producing Activities." Net proved oil and natural gas reserves
and the discounted future net cash flows related to those reserves were prepared
by EPGC's petroleum engineers and audited by Netherland, Sewell & Associates,
Inc. at December 31, 1997 and 1998. For December 31, 1999, the report was
prepared by Netherland, Sewell & Associates, Inc. Information presented in that
report was the basis for the net proved oil and natural gas reserve and
standardized measure disclosures presented below.

The following tables set forth information for the years ended December 31,
1997, 1998 and 1999, with respect to changes in the proved reserves for the EPGC
Properties.

<TABLE>
<CAPTION>
1997 1998 1999
--------------- --------------- ---------------
OIL GAS OIL GAS OIL GAS
MBBLS MMCF MBBLS MMCF MBBLS MMCF
----- ------- ----- ------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Total Proved Reserves:
Beginning of year....................... 172 13,020 3,357 84,926 4,681 86,648
Production.............................. (286) (10,627) (494) (18,781) (593) (23,100)
Revisions of previous estimates......... 87 3,048 157 (4,196) (820) 8,821
Extensions, discoveries and other
additions............................ 792 17,000 1,661 24,699 1,141 41,939
Purchases of reserves in place.......... 2,592 62,485 -- -- -- --
Sale of reserves in place............... -- -- -- -- (50) (1,758)
----- ------- ----- ------- ----- -------
End of year............................. 3,357 84,926 4,681 86,648 4,359 112,550
===== ======= ===== ======= ===== =======
</TABLE>

At December 31, 1997, 1998 and 1999, proved developed reserves were
estimated to be 2,591,179, 3,171,863 and 2,421,913, respectively, barrels of oil
and 57,725,431, 75,467,573 and 91,945,596, respectively, Mcf of natural gas.

F-26
<PAGE> 106
NOTES TO STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES FOR
THE EPGC PROPERTIES -- (CONTINUED)

Information with respect to the estimated discounted future net cash flows
for the EPGC Properties for the years ended December 31, 1997, 1998 and 1999, is
as follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1997 1998 1999
------------ ------------ ------------
<S> <C> <C> <C>
Future cash flows.......................... $270,768,332 $215,349,887 $361,475,000
Future production costs.................... (52,121,302) (75,701,717) (48,295,700)
Future development costs................... (37,151,147) (28,525,056) (58,025,200)
------------ ------------ ------------
Future net cash flows before tax........... 181,495,883 111,123,114 255,154,100
Future income taxes........................ (33,051,404) -- (52,578,529)
------------ ------------ ------------
Future net cash flows after tax............ 148,444,479 111,123,114 202,575,571
Annual discount at 10%..................... (28,866,904) (19,041,152) (38,915,695)
------------ ------------ ------------
Standardized measure of discounted future
net cash flows........................... $119,577,575 $ 92,081,962 $163,659,876
============ ============ ============
</TABLE>

The calculated weighted average sales prices utilized for the purposes of
estimating the proved reserves and future net revenue of the EPGC Properties
were $2.30 per Mcf of natural gas and $25.60 per barrel of oil at December 31,
1999, $1.97 per Mcf of natural gas and $9.62 per barrel of oil at December 31,
1998 and $2.59 per Mcf of natural gas and $15.23, per barrel of oil at December
31, 1997.

Principal changes in the estimated discounted future net cash flows for the
EPGC Properties for the years ended December 31, 1997, 1998 and 1999, are as
follows:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1997 1998 1999
------------ ------------ ------------
<S> <C> <C> <C>
Beginning of year.......................... $ 36,380,091 $119,577,575 $ 92,081,962
Oil and natural gas sales, net of
production costs...................... (27,954,133) (35,525,515) (55,844,023)
Net changes in anticipated prices and
production costs...................... (18,542,479) (84,392,132) 48,741,040
Extensions and discoveries, less related
costs................................. 36,540,575 45,423,437 83,188,499
Changes in estimated future development
costs................................. 169,981 16,783,400 14,000,000
Revision of quantity estimates........... 4,819,681 (2,385,166) 7,128,652
Purchases of minerals in place........... 97,016,653 -- --
Sales of minerals in place............... -- -- 2,095,546
Accretion of discount.................... 3,638,008 11,957,757 9,208,196
Net change in income taxes............... (13,798,205) 17,507,687 (31,623,924)
Changes in production rates and other.... 1,307,403 3,134,919 (5,316,072)
------------ ------------ ------------
End of year................................ $119,577,575 $ 92,081,962 $163,659,876
============ ============ ============
</TABLE>

F-27
<PAGE> 107

[NSAI TOP LETTERHEAD]

February 23, 2000

<TABLE>
<S> <C>
Equitable Production Company Westport Oil and Gas Company, Inc.
5555 San Felipe, Suite 210 410 Seventeenth Street, Suite 2300
Houston, Texas 77056 Denver, Colorado 80202
</TABLE>

Gentlemen:

In accordance with your request, we have estimated the proved reserves and
future revenue, as of January 1, 2000, to the Equitable Production Company
(Equitable) interest in the Equitable Gulf Region comprising certain oil and gas
properties located in Oklahoma and in Federal waters offshore Louisiana, as
listed in the accompanying tabulations. This report has been prepared using
constant prices, in effect as of December 31, 1999, and constant costs and
conforms to the guidelines of the Securities and Exchange Commission (SEC).

As presented in the accompanying summary projections, Tables I through IV,
we estimate the net reserves and future net revenue to the Equitable interest,
as of January 1, 2000, to be:

<TABLE>
<CAPTION>
NET RESERVES FUTURE NET REVENUE (M$)
------------------- -------------------------
OIL GAS PRESENT WORTH
CATEGORY (MBBL) (MMCF) TOTAL AT 10%
-------- ------- --------- --------- -------------
<S> <C> <C> <C> <C>
Proved Developed
Producing............................. 1,112.3 63,615.5 129,985.1 115,272.5
Non-Producing......................... 1,309.6 28,330.1 68,819.9 44,516.2
Proved Undeveloped...................... 1,936.7 20,604.2 56,349.1 35,495.1
------- --------- --------- ---------
Total Proved.................. 4,358.6 112,549.8 255,154.1 195,283.8
</TABLE>

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

The estimated reserves and future net revenue shown in this report 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. This report does 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 to the Equitable interest is prior to deducting state
production taxes and ad valorem taxes. Future net revenue is after deducting
these taxes, future capital costs, and operating expenses, 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.

[NSAI BOTTOM LETTERHEAD]
A-1
<PAGE> 108

[NSAI SHORT TOP LETTERHEAD]

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 nor the cost of abandoning the properties.

Oil prices used in this report are based on the December 31, 1999 NYMEX
West Texas Intermediate posted price of $25.60 per barrel, adjusted by lease for
gravity, transportation fees, and regional posted price differentials. Gas
prices used in this report are based on the December 31, 1999 NYMEX Henry Hub
spot market price of $2.30 per MMBTU, adjusted by lease for energy content,
transportation fees, and regional price differentials. Oil and gas prices are
held constant in accordance with SEC guidelines.

Lease and well operating costs are based on operating expense records of
Equitable. For non-operated properties, 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. As
requested, lease and well operating costs for the operated properties include
only direct lease and field level costs. These costs do not include the per-well
overhead expenses allowed under joint operating agreements nor do they include
the headquarters general and administrative overhead expenses of Equitable.
Lease and well operating costs are held constant in accordance with SEC
guidelines.

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

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. 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
Equitable Production Company, 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/ Fredric D. Sewell

CHR:TWB
A-2
<PAGE> 109

[RYDER SCOTT TOP LETTERHEAD]

February 24, 2000

Westport Oil and Gas Company Inc.
410 Seventeenth Street, Suite 2410
Denver, Colorado 80202

Gentlemen:

At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of Westport Oil and Gas Company Inc. as of January 1, 2000. The subject
properties are located in the States of Colorado, Kansas, Louisiana, Michigan,
New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Utah, Wyoming and
Federal waters offshore plus the Canadian Provinces of Alberta and British
Columbia. The income data were estimated using the Securities and Exchange
Commission (SEC) guidelines for future cost and price parameters.

The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. December 31, 1999 hydrocarbon prices were
used in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from December 31, 1999 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
received may differ significantly from the estimated quantities presented in
this report. A summary of the results of this study is shown below.

SEC PARAMETERS

ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
WESTPORT OIL AND GAS COMPANY INC.
AS OF JANUARY 1, 2000

<TABLE>
<CAPTION>
PROVED
----------------------------------------------------------
DEVELOPED
---------------------------- TOTAL TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate -- Barrels.......... 24,587,861 4,901,318 3,261,327 32,750,506
Plant Products -- Barrels.......... 28,145 0 0 28,145
Gas -- MMCF........................ 66,935 15,703 36,531 119,169
INCOME DATA
Future Gross Revenue............... $649,765,941 $129,587,842 $142,876,741 $922,230,524
Deductions......................... 252,032,228 30,827,004 59,579,575 342,438,807
------------ ------------ ------------ ------------
Future Net Income (FNI)............ 397,733,713 98,760,838 83,297,166 579,791,717
Discounted FNI @ 10%............ 251,480,402 48,846,942 48,771,221 349,098,565
</TABLE>

[RYDER SCOTT BOTTOM LETTERHEAD]
A-3
<PAGE> 110
Westport Oil and Gas Company Inc.
February 24, 2000
Page 2

<TABLE>
<CAPTION>
TOTAL PROBABLE TOTAL POSSIBLE
-------------- --------------
<S> <C> <C>
NET REMAINING RESERVES
Oil/Condensate -- Barrels................................. 12,330,859 644,065
Plant Products -- Barrels................................. 0 0
Gas -- MMCF............................................... 23,337 8,877
INCOME DATA
Future Gross Revenue...................................... $312,793,406 $33,053,454
Deductions................................................ $117,379,438 $ 9,472,432
------------ -----------
Future Net Income (FNI)................................... $195,413,968 $23,581,022
Discounted FNI @ 10%................................... $ 82,787,586 $14,232,855
</TABLE>

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are sales gas expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas reserves are
located.

We have included probable and possible reserves and income in this report
at the request of Westport Oil and Gas Company Inc. These data are for Westport
Oil and Gas Company Inc.'s information only and should not be included in
reports to the SEC according to the SEC guidelines.

The proved developed non-producing reserves included herein are comprised
of the shut-in and behind pipe categories. The probable developed non-producing
reserves included herein are comprised of the behind pipe category. The possible
developed non-producing reserves included herein are comprised of the shut-in
and behind-pipe categories. The various producing status categories are defined
under the tab "Reserve Definitions" in this report.

The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs and development costs. The future net income
is before the deduction of state and Federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. No attempt was made to quantify or otherwise account for any accumulated
gas production imbalances that may exist. Liquids hydrocarbon reserves account
for approximately 76 percent, gas reserves account for approximately 23.5
percent and other income from carbon dioxide and income from various overriding
royalty interests account for the remaining .5 percent of total future gross
revenue from proved reserves.

The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly.
These results are shown on each estimated projection of future production and
income presented in a later section of this report and in summary form as
follows:

DISCOUNTED FUTURE NET INCOME
AS OF JANUARY 1, 2000

<TABLE>
<CAPTION>
DISCOUNT RATE TOTAL TOTAL TOTAL
PERCENT PROVED PROBABLE POSSIBLE
------------- ------------ ----------- -----------
<S> <C> <C> <C>
8........................................... $380,016,724 $96,648,771 $15,608,465
12........................................... $322,519,383 $71,343,530 $13,021,674
15........................................... $288,986,865 $57,603,264 $11,457,922
20........................................... $245,403,934 $41,058,171 $ 9,372,890
</TABLE>

The results shown above are presented for your information and should not be
construed as our estimate of fair market value.
A-4
<PAGE> 111
Westport Oil and Gas Company Inc.
February 24, 2000
Page 3

RESERVES INCLUDED IN THIS REPORT

The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The probable
reserves and possible reserves included herein conform to definitions of
probable and possible reserves approved by the Society of Petroleum Engineers
and the World Petroleum Congress (WPC). Our definitions of proved, probable, and
possible reserves are included under the tab "Reserve Definitions" in this
report.

The probable reserves are less certain to be recovered than the proved
reserves and reserves classified as possible are less certain to be recovered
than those in the probable category. The reserves and income quantities
attributable to the different reserve classifications that are included herein
have not been adjusted to reflect the varying degrees of risk associated with
them and thus are not comparable.

ESTIMATES OF RESERVES

In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive in our opinion. Reserves were estimated by the volumetric
method in those cases where there were inadequate historical performance data to
establish a definitive trend or where the use of production performance data as
a basis for the reserve estimates was considered to be inappropriate.

The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.

FUTURE PRODUCTION RATES

Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for market
conditions where appropriate, until a decline in ability to produce was
anticipated. An estimated rate of decline was then applied to depletion of the
reserves. If a decline trend has been established, this trend was used as the
basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Westport Oil and Gas Company Inc.

The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates. Projected additional response to secondary recovery
projects may occur earlier or later than anticipated in our estimates of their
future production rates.

A-5
<PAGE> 112
Westport Oil and Gas Company Inc.
February 24, 2000
Page 4

HYDROCARBON PRICES

Westport Oil and Gas Company Inc. furnished us with oil and condensate
prices in effect at December 31, 1999 and these prices were held constant except
for known and determinable escalations. In accordance with Securities and
Exchange Commission guidelines, changes in liquid prices subsequent to December
31, 1999 were not taken into account in this report.

Westport Oil and Gas Company Inc. furnished us with plant product prices in
effect at December 31, 1999 and these prices were held constant until depletion
of the properties.

Westport Oil and Gas Company Inc. furnished us with gas prices in effect at
December 31, 1999 and with its forecasts of future gas prices which take into
account SEC guidelines, current spot market prices, contract prices, and fixed
and determinable price escalations where applicable. In accordance with SEC
guidelines, the future gas prices used in this report make no allowances for
future gas price increases which may occur as a result of inflation nor do they
make any allowance for seasonal variations in gas prices which may cause future
yearly average gas prices to be somewhat different than December 31, 1999 gas
prices. For gas sold under contract, the contract gas price including fixed and
determinable escalations, exclusive of inflation adjustments, was used until the
contract expires and then was adjusted to the current market price for the area
and held at this adjusted price to depletion of the reserves.

COSTS

Operating costs for the leases and wells in this report were supplied by
Westport Oil and Gas Company Inc. and are based on their operating expense
reports and include only those costs directly applicable to the leases or wells.
When applicable, the operating costs include a portion of general and
administrative costs allocated directly to the leases and wells under terms of
operating agreements. Development costs were furnished to us by Westport Oil and
Gas Company Inc. and are based on authorizations for expenditure for the
proposed work or actual costs for similar projects. The current operating and
development costs were held constant throughout the life of the properties. The
estimated net cost of abandonment after salvage was included for all properties
where abandonment costs net of salvage are significant. These estimates of net
abandonment cost or salvage value supplied by Westport Oil and Gas Company, Inc.
were accepted without independent verification. At the request of Westport Oil
and Gas Company Inc., their estimate of zero abandonment costs after salvage
value for the other onshore properties was used in this report. Ryder Scott has
not performed a detailed study of the abandonment costs nor the salvage value
and makes no warranty for Westport Oil and Gas Company Inc.'s estimate. No
deduction was made for indirect costs such as general administration and
overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments that are not charged directly to the leases or wells.

GENERAL

Table A presents a one line summary of proved reserve and income data for
each of the subject properties which are ranked according to their future net
income discounted at 10 percent per year. Table B presents a one line summary of
gross and net reserves and income data for each of the subject properties. Table
C presents a one line summary of initial basic data for each of the subject
properties. Tables 1 through 6 present our estimated projection of production
and income by years beginning January 1, 2000, by reserve category. These tables
are all included in the "Summary Report". Tables 7 through 2345 present our
estimated projection of production and income by years beginning January 1,
2000, by state, field, and lease or well. These tables are presented in the
"Detail Report" (3 volumes).

A-6
<PAGE> 113
Westport Oil and Gas Company Inc.
February 24, 2000
Page 5

While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.

The estimates of reserves presented herein were based upon a detailed study
of the properties in which Westport Oil and Gas Company Inc. owns an interest;
however, we have not made any field examination of the properties. No
consideration was given in this report to potential environmental liabilities
which may exist nor were any costs included for potential liability to restore
and clean up damages, if any, caused by past operating practices. Westport Oil
and Gas Company Inc. has informed us that they have furnished us all of the
accounts, records, geological and engineering data, and reports and other data
required for this investigation. The ownership interests, prices, and other
factual data furnished by Westport Oil and Gas Company Inc. were accepted
without independent verification.

Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.

This report was prepared for the exclusive use of Westport Oil and Gas
Company Inc. The data, work papers, and maps used in this report are available
for examination by authorized parties in our offices. Please contact us if we
can be of further service.

Very truly yours,

RYDER SCOTT COMPANY L.P.

/s/ Larry T. Nelms
Larry T. Nelms, P.E.
Senior Vice President

LTN:ph

[SEAL]

[RYDER SCOTT LOGO]
A-7
<PAGE> 114

[WESTPORT LOGO]
<PAGE> 115

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13 -- OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The estimated expenses in connection with the issuance and distribution of
the securities being registered, other than underwriting discounts and
commissions are set forth in the following table. The company will pay all
expenses of issuance and distribution. Each amount, except for the SEC and New
York Stock Exchange fees, is estimated.

<TABLE>
<S> <C>
SEC registration fees....................................... $26,400
NASD filing fee............................................. $10,500
New York Stock Exchange application listing fee............. $ *
Transfer agent's and registrar's fees and expenses.......... $ *
Printing and engraving expenses............................. $ *
Legal fees and expenses..................................... $ *
Accounting fees and expenses................................ $ *
Miscellaneous............................................... $ *
-------
Total............................................. $ *
=======
</TABLE>

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

* To be included by amendment.

ITEM 14 -- INDEMNIFICATION OF DIRECTORS AND OFFICERS

Our certificate of incorporation provides that no director shall be
personally liable to us or our stockholders for monetary damages for breach of
fiduciary duties as a director for any act or omission; provided, however, that
the director may be liable for any breach of his duty of loyalty to us or our
stockholders, for any act or omission not in good faith or which involves
intentional misconduct or a knowing violation of law, under Section 174 of the
Delaware General Corporation Law, or for any transaction from which he derived
an improper personal benefit.

Our bylaws provide that we shall, to the maximum extent permitted by the
Delaware General Corporation Law, indemnify all persons whom it may indemnify
under Delaware law. Section 145 of the Delaware General Corporation Law permits
a corporation, under specified circumstances, to indemnify its directors,
officers, employees or agents against expenses (including attorneys' fees),
judgments, fines and amounts paid in settlements actually and reasonably
incurred by them in connection with any action, suit or proceeding brought by
third parties by reason of the fact that they were or are directors, officers,
employees or agents of the corporation, if such directors, officers, employees
or agents acted in good faith and in a manner they 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 reason to believe their conduct was
unlawful. In a derivative action, i.e., one by or in the right of the
corporation, indemnification may be made only for expenses actually and
reasonably incurred by directors, officers, employees or agents in connection
with the defense or settlement of an action or suit, and only with respect to a
matter as to which they shall have acted in good faith and in a manner they
reasonably believed to be in or not opposed to the best interests of the
corporation, except that no indemnification shall be made if such person shall
have been adjudged liable to the corporation, unless and only to the extent that
the court in which the action or suit was brought shall determine upon
application that the defendant directors, officers, employees or agents are
fairly and reasonably entitled to indemnity for such expenses despite such
adjudication of liability.

We have entered into indemnification agreements with our directors and
officers, which indemnify each person to the fullest extent permitted by
Delaware law. Pursuant to the agreements, we also agree to hold harmless and
indemnify each person against expenses incurred by reason of the fact that the
person is or was a director, officer, employee or agent of us, if such person
acted in good faith and in a manner he

II-1
<PAGE> 116

reasonably believed to be in or not opposed to our best interest, and in the
case of a criminal proceeding, had no reasonable cause to believe that his
conduct was unlawful.

Pursuant to the Shareholders' Agreement, we have agreed to indemnify ERI
Investments, Inc., Westport Energy, LLC and each of their directors, officers
and controlling persons to the extent permitted by law against any losses,
claims, damages or liabilities to which such person may become subject under the
Securities Act of 1933 that arise out of any untrue or alleged statement of
material fact or any omission of a material fact required to be contained in a
registration statement, prospectus, application or other documentation to be
filed with the Securities and Exchange Commission.

Expenses for the defense of any action for which indemnification may be
available shall be advanced by the company under certain circumstances. The
general effect of the foregoing provisions may be to reduce the circumstances
which an officer or director may be required to bear the economic burden of the
foregoing liabilities and expenses. Directors and officers will be covered by
liability insurance indemnifying them against damages arising out of certain
kinds of claims which might be made against them based on their negligent acts
or omissions while acting in their capacity as such.

ITEM 15 -- RECENT SALES OF UNREGISTERED SECURITIES

During the past three years, we have sold the securities set forth below
which were not registered under the Securities Act:

- In April 2000, 10,375,334, 22,500 and 22,500 shares of our common stock
were issued to Westport Energy LLC, Donald D. Wolf Family Limited
Partnership and Barth E. Whitham, respectively, in connection with the
transaction between Westport Oil and Gas and EPGC.

- In September 1999, 10,157,435 shares (adjusted to reflect subsequent
stock splits effected prior to the transaction between Westport Oil and
Gas and EPGC) of our common stock were issued to Equitable Production
Company in anticipation of the transaction between Westport Oil and Gas
and EPGC.

The sales of securities in the transactions described above were deemed to
be exempt from registration under the Securities Act in reliance upon Section
4(2) of the Securities Act. The recipients of securities in each transaction
represented their intentions to acquire the securities for investment only and
not with a view to or for sale in connection with any distribution thereof and
appropriate legends were affixed to the securities issued in such transactions.
All recipients had adequate access to information about us.

ITEM 16 -- EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Exhibits

II-2
<PAGE> 117

<TABLE>
<CAPTION>
EXHIBIT
NO. EXHIBITS
------- --------
<C> <S>
10.1 -- Credit Agreement, dated March 31, 2000, by and among
Westport Oil and Gas Company, Inc. and a syndicate of
banks led by Bank of America, N.A., as agent.
10.2 -- Shareholders' Agreement, dated as of March 9, 2000, by
and among Equitable Production (Gulf) Company, Westport
Energy Corporation and Equitable Production Company.
10.3 -- Shareholders' Agreement, dated as of March 9, 2000, by
and among Westport Energy Corporation, Barth E. Whitham
and Donald D. Wolf Family Limited Partnership.
10.4 -- Westport Resources Corporation 2000 Stock Incentive
Plan.+
10.5 -- Form of Indemnification Agreement.
10.6 -- Westport Resources Corporation Annual Incentive Plan
2000.
10.7 -- Employment Agreement between Westport and Donald D. Wolf
dated May 8, 2000.
10.8 -- Employment Agreement between Westport and Barth E.
Whitman dated May 8, 2000.
21 -- Subsidiaries of the Registrant.
23.1 -- Consent of Arthur Andersen LLP.
23.2 -- Consent of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
(included in its opinion filed as Exhibit 5 hereto).+
23.3 -- Consent of Ryder Scott Company L.P.
23.4 -- Consent of Netherland, Sewell & Associates, Inc.
24 -- Power of Attorney (included on the signature page
hereto).+
27 -- Financial Data Schedule (included in SEC-filed copy
only).
</TABLE>

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

+ To be filed by amendment.

ITEM 17 -- UNDERTAKINGS

The undersigned registrant hereby undertakes to provide to the underwriters
at the closing specified in the underwriting agreement, certificates in such
denominations and registered in such names as required by the underwriters to
permit prompt delivery to each purchaser.

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

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus filed as part
of this registration statement in reliance upon Rule 430A and contained in
a form of prospectus filed by the registrant pursuant to Rule 424(b)(1)

II-3
<PAGE> 118

or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be
part of this registration statement as of the time it was declared
effective.

(2) For purposes of determining any liability under the Securities Act
of 1933, each post-effective amendment that contains a form of prospectus
shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.

II-4
<PAGE> 119

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Registration Statement on Form S-1 to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Denver, State of Colorado, on June 29, 2000.

WESTPORT RESOURCES CORPORATION

By: /s/ DONALD D. WOLF
----------------------------------
Donald D. Wolf
Chairman and Chief Executive Officer

POWER OF ATTORNEY

The undersigned directors and officers of Westport Resources Corporation
hereby constitute and appoint Donald D. Wolf and Barth E. Whitham, with full
power to act and with full power of substitution and resubstitution, our true
and lawful attorney-in-fact and agent with full power to execute in our name and
behalf in the capacities indicated below any and all amendments (including
post-effective amendments and amendments thereto) to this Registration Statement
and to file the same, with all exhibits and other documents relating thereto and
any registration statement relating to any offering made pursuant to this
Registration Statement that is to be effective upon filing pursuant to Rule
462(b) under the Securities Act with the SEC and hereby ratify and confirm all
that such attorney-in-fact or his substitute shall lawfully do or cause to be
done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended,
this registration statement has been signed by the following persons in the
capacities and on the dates indicated below:

<TABLE>
<CAPTION>
NAME TITLE DATE
---- ----- ----
<C> <S> <C>

/s/ DONALD D. WOLF Chairman, Chief Executive Officer June 29, 2000
----------------------------------------------------- and Director (Principal
Donald D. Wolf Executive Officer)

/s/ JAMES H. SHONSEY Chief Financial Officer June 29, 2000
----------------------------------------------------- (Principal Financial Officer)
James H. Shonsey

/s/ KENNETH D. ANDERSON Vice President -- Accounting June 29, 2000
----------------------------------------------------- (Principal Accounting Officer)
Kenneth D. Anderson

/s/ MICHAEL RUSSELL Director June 29, 2000
-----------------------------------------------------
Michael Russell

/s/ MURRY S. GERBER Director June 29, 2000
-----------------------------------------------------
Murry S. Gerber

/s/ DAVID L. PORGES Director June 29, 2000
-----------------------------------------------------
David L. Porges

/s/ JAMES M. FUNK Director June 29, 2000
-----------------------------------------------------
James M. Funk
</TABLE>

S-1
<PAGE> 120

<TABLE>
<CAPTION>
NAME TITLE DATE
---- ----- ----
<C> <S> <C>

/s/ ALEX M. CRANBERG Director June 29, 2000
-----------------------------------------------------
Alex M. Cranberg

/s/ WILLIAM F. WALLACE
-----------------------------------------------------
William F. Wallace Director June 29, 2000
</TABLE>

S-2
<PAGE> 121

EXHIBIT INDEX

<TABLE>
<CAPTION>
EXHIBIT
NO. EXHIBITS
------- --------
<C> <S>
1 -- Form of Underwriting Agreement.+
2.1 -- Agreement and Plan of Merger, dated as of March 9, 2000,
by and among Westport Oil and Gas Company, Inc., Westport
Energy Corporation, Equitable Production Company,
Equitable Production (Gulf) Company and EPGC Merger Sub
Corporation.
3.1 -- Certificate of Incorporation of the Registrant.+
3.2 -- Bylaws of the Registrant.+
4 -- Specimen Certificate for shares of Common Stock of the
Registrant.+
5 -- Opinion of Akin, Gump, Strauss, Hauer & Feld, L.L.P.+
10.1 -- Credit Agreement, dated March 31, 2000, by and among
Westport Oil and Gas Company, Inc. and a syndicate of
banks led by Bank of America, N.A., as agent.
10.2 -- Shareholders' Agreement, dated as of March 9, 2000, by
and among Equitable Production (Gulf) Company, Westport
Energy Corporation and Equitable Production Company.
10.3 -- Shareholders' Agreement, dated as of March 9, 2000, by
and among Westport Energy Corporation, Barth E. Whitham
and Donald D. Wolf Family Limited Partnership.
10.4 -- Westport Resources Corporation 2000 Stock Incentive
Plan.+
10.5 -- Form of Indemnification Agreement.
10.6 -- Westport Resources Corporation Annual Incentive Plan
2000.
10.7 -- Employment Agreement between Westport and Donald D. Wolf
dated May 8, 2000.
10.8 -- Employment Agreement between Westport and Barth E.
Whitman dated May 8, 2000.
21 -- Subsidiaries of the Registrant.
23.1 -- Consent of Arthur Andersen LLP.
23.2 -- Consent of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
(included in its opinion filed as Exhibit 5 hereto).+
23.3 -- Consent of Ryder Scott Company L.P.
23.4 -- Consent of Netherland, Sewell & Associates, Inc.
24 -- Power of Attorney (included on the signature page
hereto).+
27 -- Financial Data Schedule (included in SEC-filed copy
only).
</TABLE>

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

+ To be filed by amendment.