WESTPORT RESOURCES CORP, 424B4, 2000-10-20

WESTPORT RESOURCES CORP
424B4, 2000-10-20
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

Filed Pursuant to Rule 424(b)(4)
Registration No. 333-40422
9,150,000 Shares

[WESTPORT LOGO]

WESTPORT RESOURCES CORPORATION

Common Stock

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

Prior to this offering, there has been no public market for our common
stock. Our common stock has been approved for listing on The New York Stock
Exchange under the symbol "WRC."

We are selling 6,500,000 shares of common stock and the selling
stockholders are selling 2,650,000 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 a maximum of 1,350,000
additional shares from us to cover over-allotments of shares.

INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 9.

<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO
PRICE TO DISCOUNTS AND PROCEEDS TO SELLING
PUBLIC COMMISSIONS WESTPORT STOCKHOLDERS
------------ ------------- ----------- ------------
<S> <C> <C> <C> <C>
Per Share............................ $15.00 $1.0125 $13.9875 $13.9875
Total................................ $137,250,000 $9,264,375 $90,918,750 $37,066,875
</TABLE>

Delivery of the shares of common stock will be made on or about October 25,
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 October 19, 2000.
<PAGE> 2

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TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUMMARY...................... 1
RISK FACTORS............................ 9
SPECIAL NOTE REGARDING FORWARD-LOOKING
STATEMENTS............................ 18
USE OF PROCEEDS......................... 19
DIVIDEND POLICY......................... 19
DILUTION................................ 20
CAPITALIZATION.......................... 21
SELECTED CONSOLIDATED FINANCIAL DATA.... 22
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
OF WESTPORT RESOURCES CORPORATION..... 24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS............................ 30
BUSINESS AND PROPERTIES................. 40
MANAGEMENT.............................. 54
CERTAIN TRANSACTIONS.................... 63
</TABLE>

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PRINCIPAL AND SELLING STOCKHOLDERS...... 64
DESCRIPTION OF CAPITAL STOCK............ 66
SHARES ELIGIBLE FOR FUTURE SALE......... 68
UNITED STATES TAX CONSEQUENCES TO
NON-U.S. HOLDERS...................... 69
UNDERWRITING............................ 72
NOTICE TO CANADIAN RESIDENTS............ 76
LEGAL MATTERS........................... 77
EXPERTS................................. 77
INDEPENDENT PETROLEUM ENGINEERS......... 77
WHERE YOU CAN FIND MORE INFORMATION..... 77
GLOSSARY OF OIL AND NATURAL GAS TERMS... 78
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. THIS DOCUMENT WILL BE AMENDED OR
SUPPLEMENTED AFTER THAT DATE TO REFLECT ANY SUBSEQUENT MATERIAL CHANGES DURING
THE PROSPECTUS DELIVERY PERIOD SPECIFIED BELOW. FOR ADDITIONAL INFORMATION ABOUT
WESTPORT REQUIRED TO BE FILED UNDER THE SECURITIES EXCHANGE ACT OF 1934, YOU
SHOULD VISIT THE SECURITIES AND EXCHANGE COMMISSION'S WEBSITE AT WWW.SEC.GOV.

DEALER PROSPECTUS DELIVERY OBLIGATION

UNTIL NOVEMBER 13, 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> 3

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 on April 7, 2000
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 of its parent company, Equitable Production
Company. 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, the
information contained in this prospectus gives effect to a three-for-two common
stock split effected on October 17, 2000. 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 78.

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.

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 recovery methods. 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 June 30, 2000, we had proved reserves of 459.1 billion cubic feet
equivalent of natural gas, or Bcfe, with a net present value, which is the
pre-tax future net revenues discounted at 10%, of $958.3 million and a
standardized measure value of $768.6 million based on NYMEX prices of $32.50 per
barrel of oil and $4.33 per million British thermal units, or Mmbtu, of natural
gas. These reserves, of which 50% were natural gas and 80% were classified as
proved developed, had a reserve life index of 7.5 years. We operate over 73% of
the net present value of our reserves, 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 30.5
Bcfe in the first half of 2000. The following table sets forth the volume and
net present value of our proved reserves at mid-year 2000 and a summary of our
second quarter 2000 production by area:

<TABLE>
<CAPTION>
AS OF JUNE 30, 2000 SECOND QUARTER 2000
----------------------------------------- ----------------------------
PROVED NET PRESENT % OF NET AVERAGE
RESERVES VALUE (IN PRESENT PRODUCTION % OF
AREA (Bcfe) MILLIONS) VALUE (Mmcfe/d) PRODUCTION
---- ----------- -------------- ---------- ------------- ------------
<S> <C> <C> <C> <C> <C>
Gulf of Mexico................... 154.8 $426.8 45% 90.3 52%
Rocky Mountains.................. 204.4 345.3 36 58.8 34
West Texas/Mid-Continent......... 62.2 117.5 12 11.2 7
Gulf Coast....................... 37.7 68.7 7 11.7 7
----- ------ --- ----- ---
Total.................. 459.1 $958.3(1) 100% 172.0 100%
===== ====== === ===== ===
</TABLE>

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<PAGE> 4

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

(1) The net present value is the pre-tax future net revenues discounted at 10%.
The corresponding standardized measure, which is the after-tax future net
revenues discounted at 10%, is $768.6 million. The difference between the
net present value and the standardized measure is the effect of income tax
discounted at 10%.

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
increase production and 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 current 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
expanded two secondary recovery projects. We have identified significant
prospective exploitation projects both onshore and offshore. 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, our most valuable property in the Gulf of
Mexico based upon net present value and our most active offshore area. Onshore,
we plan to drill more than 100 development wells in 2000. As of June 30, 2000,
65 of these wells had been drilled and 60 were successful.

We acquired the West Cameron 180/198 complex in 1997, and have increased
production from approximately 30 Mmcfe/d at the date of acquisition to
approximately 55 million cubic feet equivalent of natural gas per day, or
Mmcfe/d, for the quarter ended June 30, 2000. In our most active onshore areas,
Gooseberry, South Fryburg Tyler and Bonepile, we have increased gross production
through exploitation from approximately 13 Mmcfe/d for the quarter ended March
31, 1997 to approximately 24 Mmcfe/d for the quarter ended June 30, 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 $58
million to exploit these acquired properties and added reserves at an average
cost of $0.50 per Mcfe, thereby reducing average acquisition costs by over 13%
to $0.78 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 58% 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 June 30, 2000, we
had a 67-block exploration inventory in the Gulf of Mexico, in addition to 65
developed blocks, several of which contain

2
<PAGE> 5

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 linear 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.

Onshore, we hold interests in approximately 144,000 gross (approximately
70,000 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 merger between Westport Oil and Gas and EPGC, lease operating
expense for the six months ended June 30, 2000 was further reduced to $0.55 per
Mcfe. 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......................... 6,500,000 shares

Common stock offered by the
selling stockholders............. 2,650,000 shares

Common stock to be outstanding
after this offering(1)........... 37,384,041 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
our credit agreement, along with cash flow
from operations, to pursue exploitation,
acquisition and exploration activities and
for general corporate purposes.

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

(1) Excludes 4,110,813 shares of common stock reserved for issuance under our
stock option plan, of which options in respect of 1,527,441 shares have been
granted.

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<PAGE> 6

RISK FACTORS

We incurred net losses of $9.4 million, $49.4 million and $3.1 million in
1997, 1998 and 1999, respectively. Prospective investors should carefully
consider the matters set forth under the caption "Risk Factors" beginning on
page 9, as well as the other information set forth in this prospectus, including
that our future operating results are difficult to forecast and the 3-D seismic
data and other technology we use cannot eliminate exploration risk, reserve
estimate inaccuracies may materially affect the quantities and net present value
of our reserves, our Gulf of Mexico assets subject us to higher reserve
replacement needs, and the oil and natural gas business involves many operating
and financial risks. One or more of these matters could negatively impact our
ability to implement successfully our business strategy.

4
<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, derived from the
consolidated financial statements of Westport Oil and Gas, for the six months
ended June 30, 1999 and 2000, derived from our consolidated financial
statements, and pro forma information prepared as if the merger between Westport
Oil and Gas and EPGC had taken place as of January 1, 1999 with respect to the
statement of operations data. The as adjusted balance sheet data give effect to:

- the sale by us of 6,500,000 shares of common stock in this offering at an
initial public offering price of $15.00 per share and 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
------------------------------------------------------ -------------------------
SIX MONTHS
ENDED SIX MONTHS
YEAR ENDED DECEMBER 31, JUNE 30, YEAR ENDED ENDED
-------------------------------- ------------------- DECEMBER 31, JUNE 30,
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 $ 31,891 $ 77,548 $138,635 $96,480
Operating costs and expenses:
Lease operating expense....... 19,583 21,554 22,916 10,139 15,480 30,131 16,695
Production taxes.............. 5,923 3,888 5,742 2,186 4,644 5,742 4,644
Exploration................... 7,424 14,664 7,314 2,091 6,263 7,314 6,263
Depletion, depreciation and
amortization................ 23,659 36,264 25,210 16,309 22,576 58,298 32,702
Impairment of proved
properties.................. 5,765 8,794 3,072 -- -- 3,072 --
Impairment of unproved
properties.................. 380 1,898 2,273 3 1,541 2,273 1,541
General and administrative.... 5,316 5,913 5,297 2,995 6,587(1) 8,104 7,289(1)
--------- --------- -------- -------- -------- -------- -------
Total operating
expenses............. 68,050 92,975 71,824 33,723 57,091 114,934 69,134
--------- --------- -------- -------- -------- -------- -------
Operating income
(loss)............... (4,961) (41,470) 1,939 (1,832) 20,457 23,701 27,346
Other income (expense):
Interest expense.............. (5,635) (8,323) (9,207) (4,577) (5,288) (13,301) (6,311)
Interest income............... 309 403 489 215 375 489 375
Gain (loss) on sale of
assets -- net............... (13) -- 3,637 4,397 (11) 3,637 (11)
Other......................... (54) 29 16 20 32 16 32
--------- --------- -------- -------- -------- -------- -------
Income (loss) before income
taxes......................... (10,354) (49,361) (3,126) (1,777) 15,565 14,542 21,431
Benefit (provision) for income
taxes......................... 973 -- -- -- (4,959) (5,090) (7,501)
--------- --------- -------- -------- -------- -------- -------
Net income (loss)............... $ (9,381) $ (49,361) $ (3,126) $ (1,777) $ 10,606 $ 9,452 $13,930
========= ========= ======== ======== ======== ======== =======
Weighted average number of
common shares outstanding:
Basic......................... 9,326 11,004 14,727 13,806 22,785 29,964 30,867
========= ========= ======== ======== ======== ======== =======
Diluted....................... 9,326 11,004 14,727 13,806 22,975 30,101 31,057
========= ========= ======== ======== ======== ======== =======
Net income (loss) per common
share:
Basic......................... $ (1.01) $ (4.49) $ (0.21) $ (0.13) $ 0.47 $ 0.32 $ 0.45
========= ========= ======== ======== ======== ======== =======
Diluted....................... $ (1.01) $ (4.49) $ (0.21) $ (0.13) $ 0.46 $ 0.31 $ 0.45
========= ========= ======== ======== ======== ======== =======
Supplemental net income per
common share(2):
Basic......................... $ 0.17 $ 0.44 $ 0.38 $ 0.44
======== ======== ======== =======
Diluted....................... $ 0.17 $ 0.44 $ 0.38 $ 0.43
======== ======== ======== =======
</TABLE>

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<TABLE>
<CAPTION>
AS OF JUNE 30, 2000
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Cash........................................................ $ 15,684 $ 15,684
Working capital............................................. 36,559 36,559
Total assets................................................ 514,067 514,067
Total long-term debt........................................ 155,462 65,701
Total debt.................................................. 156,129 66,368
Stockholders' equity........................................ 318,898 408,659
</TABLE>

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

(2) Historical supplemental net income per common share gives effect to the
issuance of 6,500,000 shares of common stock in connection with this
offering and the application of the net proceeds from this offering to repay
a portion of the outstanding debt. Pro forma supplemental net income per
common share gives effect to (i) the merger between Westport Oil and Gas and
EPGC, (ii) the issuance of 6,500,000 shares of common stock in connection
with this offering and (iii) the application of the net proceeds from this
offering to repay outstanding debt.

(3) 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. While Adjusted EBITDA should not be considered in
isolation or as a substitute for net income (loss), operating income (loss),
cash flow provided by operating activities or other income or cash flow data
prepared in accordance with generally accepted accounting principles or as
an indicator of a company's financial performance, we believe that it
provides additional information with respect to our ability to meet our
future debt service, capital expenditures and working capital requirements.
When evaluating Adjusted EBITDA, investors should consider, among other
factors, (i) increasing or decreasing trends in Adjusted EBITDA, (ii)
whether Adjusted EBITDA has remained at positive levels historically and
(iii) how Adjusted EBITDA compares to levels of interest expense. Because
Adjusted EBITDA excludes some, but not all, items that affect net income and
may vary among companies, the Adjusted EBITDA presented above may not be
comparable to similarly titled measures of other companies. While we believe
that Adjusted EBITDA may provide additional information with respect to our
ability to meet our future debt service, capital expenditures and working
capital requirements, certain functional or legal requirements of our
business may require us to utilize our available funds for other purposes.

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SUMMARY OPERATING AND RESERVE DATA

The following table sets forth summary operating and reserve data. The
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. Summaries of Ryder Scott's and Netherland,
Sewell's reports on our proved reserves as of December 31, 1999 and June 30,
2000 are 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 merger between Westport Oil and
Gas and EPGC had taken place on January 1, 1999 for production, price and cost
data.

<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
----------------------------------------------- -------------------------
SIX MONTHS
ENDED SIX MONTHS
YEAR ENDED DECEMBER 31, JUNE 30, YEAR ENDED ENDED
--------------------------- ----------------- DECEMBER 31, JUNE 30,
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 1,667 1,707 3,893 1,814
Natural gas (Mmcf)......... 5,265 8,101 13,313 6,661 13,330 36,413 19,185
NGL (Mbbls)(1)............. -- -- -- -- 29 168 65
Total Mmcfe................ 23,949 28,999 33,113 16,663 23,746 60,779 30,459
AVERAGE PRICES(2):
Oil (per bbl).............. $ 17.35 $ 10.79 $ 16.45 $ 12.42 $ 26.46 $ 16.69 $ 26.47
Natural gas (per Mcf)...... 1.71 1.68 2.06 1.68 3.02 2.19 2.89
NGL (per bbl)(1)........... -- -- -- -- 20.90 11.15 22.09
Total per Mcfe............. 2.63 1.77 2.47 1.92 3.62 2.41 3.45
AVERAGE COSTS (PER MCFE):
Lease operating expense.... $ 0.82 $ 0.74 $ 0.69 $ 0.61 $ 0.65 $ 0.50 $ 0.55
General and
administrative........... 0.22 0.20 0.16 0.18 0.28(3) 0.13 0.24(3)
Depletion, depreciation and
amortization............. 0.99 1.25 0.76 0.98 0.95 0.96 1.07
</TABLE>

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

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

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

(3) Includes compensation expense of $3.4 million recorded as a result of a
one-time repurchase of employee stock options in March 2000 in connection
with the merger between Westport Oil and Gas and EPGC. Excluding this
one-time compensation expense, general and administrative costs per Mcfe
would have been $0.13 for each of the six-month historical period ended June
30, 2000 and the six-month pro forma period ended June 30, 2000.

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<TABLE>
<CAPTION>
AS OF
AS OF DECEMBER 31, JUNE 30,
------------------------------ --------
1997 1998 1999 2000
-------- -------- -------- --------
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil (Mbbls).................................... 27,991 24,376 32,750 38,020
Natural gas (Mmcf)............................. 28,576 100,285 119,169 229,039
NGL (Mbbls).................................... 36 50 28 329
Total Mmcfe.................................... 196,737 246,840 315,838 459,135
Percent proved developed....................... 91.7% 82.1% 82.2% 79.7%
Net present value (in thousands)............... $155,408 $111,284 $349,099(1) $958,288(1)
Standardized measure (in thousands)(2)......... $153,550 $104,606 $322,435 $768,562
Reserve life index (in years)(3)............... 8.2 8.5 9.5 7.5
</TABLE>

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

(1) The difference in the net present value from December 31, 1999 to June 30,
2000 resulted almost entirely from (i) the addition of 129.8 Bcfe of proved
reserves acquired in connection with the merger between Westport Oil and Gas
and EPGC and (ii) the increase in commodity prices used to determine net
present value (from $25.60 to $32.50 per bbl of oil and $2.30 to $4.33 per
Mmbtu of natural gas).

(2) The standardized measure is the value of the future after-tax net revenue
discounted at 10%. The difference between the net present value and the
standardized measure is the effect of income taxes discounted at 10%.

(3) As of December 31, 1997, 1998 and 1999, calculated by dividing year-end
proved reserves by annual production for the period. As of June 30, 2000,
calculated by dividing June 30, 2000 proved reserves by annualized first
half 2000 production.

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RISK FACTORS

Our known material risks and uncertainties 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.

RISKS RELATING TO OUR BUSINESS

OIL AND NATURAL GAS PRICES FLUCTUATE WIDELY, AND LOW PRICES COULD HARM 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. We have had considerable losses
in previous years as a result, in part, of this commodity price volatility.
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.

9
<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. Our planned exploitation and exploration projects and
acquisition activities may not result in significant additional reserves, and
our efforts to drill productive wells at favorable finding costs may not be
successful.
10
<PAGE> 13

RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN. ANY MATERIAL INACCURACIES IN OUR
RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS, SUCH AS THE DISCOUNT RATE USED,
COULD CAUSE THE QUANTITIES AND NET PRESENT VALUE OF OUR RESERVES TO BE
OVERSTATED.

There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond our control, that could cause the
quantities and net present value of our reserves to be overstated. 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 net 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. Please see "Business and Properties -- Proved
Reserves" beginning on page 46 for a discussion of our proved oil and natural
gas reserves.

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.

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. For example, we have
historically participated in property auctions, including the Federal offshore
lease auctions. To the extent our competitors are able to pay more for auction
properties than we are, we will be at a competitive disadvantage. Further, many
of our competitors may enjoy technological advantages and may be able to
implement new technologies more

11
<PAGE> 14

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. Failure to comply with these laws
and regulations 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.
We cannot be certain 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.

Please see "Business and Properties -- Regulation" beginning on page 50 for
additional information regarding laws and regulations affecting our business.

12
<PAGE> 15

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

Other companies operate approximately 27% of the net present value of our
reserves. 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 prevent the
realization of our targeted returns on capital in drilling or acquisition
activities. The success and timing of 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.

In addition, our offshore operations in the Gulf of Mexico 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. For example, some of our offshore
facilities in the Gulf of Mexico were damaged by

13
<PAGE> 16

a hurricane in 1998. 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. However, 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 be certain 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. We may
not be successful in identifying or acquiring any material property interests,
which could prevent us from replacing our reserves and adversely affect our
operations and financial condition. 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.

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. We have
incurred losses as a result of hedging arrangements in the past. 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. If we choose not to engage
in hedging arrangements in the future, we may be more adversely affected by
changes in oil and natural gas prices than our competitors who engage in hedging
arrangements.

14
<PAGE> 17

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 adversely impact our ability to deliver the oil
and natural gas we produce to market in an efficient manner, which could harm
our financial condition and results of operations. We deliver oil and natural
gas through gathering systems and pipelines that we do not own. These facilities
may not be available to us in the future. Our ability to produce and market oil
and natural gas is 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 75.3% of our outstanding common stock (approximately 72.7% if the
underwriters exercise their over-allotment option in full). Accordingly, these
stockholders, acting together, 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 merger between Westport Oil and Gas and 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.

15
<PAGE> 18

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 was 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. For example, changes in regulations applicable to the Gulf of
Mexico could adversely affect our business and operations, and, thus, result in
significant fluctuations in the trading price of our common stock.

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 is currently
prohibited by our credit agreement and may be similarly restricted in the
future.

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 generally only our chairman, president or
secretary may call a special meeting of the stockholders;

- provisions that permit our board of directors to increase the number of
directors up to fifteen 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 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.

16
<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 $4.06 per share, based upon an initial
public offering price of $15.00 per share, because the price you pay will be
substantially greater than the net tangible book value per share of $10.94 for
the shares you acquire. This dilution is due in large part to the fact that
prior investors paid an average price of $11.88 per share when they purchased
their shares of common stock, which is substantially less than the initial
public offering price of $15.00 per share.

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 37,384,041 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.

In addition, some of our current shareholders have "demand" and/or
"piggyback" registration rights in connection with future offerings of our
common stock. "Demand" rights enable the holders to demand that their shares be
registered and may require us to file a registration statement under the
Securities Act at our expense. "Piggyback" rights provide for notice to the
relevant holders of our stock if we propose to register any of our securities
under the Securities Act, and grant such holders the right to include their
shares in the registration statement. All holders with registration rights have
agreed not to exercise their rights until 180 days following the date of this
prospectus without the consent of Credit Suisse First Boston Corporation.

17
<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.

18
<PAGE> 21

USE OF PROCEEDS

We will receive net proceeds from our sale of 6,500,000 shares of common
stock of approximately $89.8 million ($108.6 million if the underwriters
exercise their over-allotment option in full), at the initial public offering
price of $15.00 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. Following application of the net proceeds of this offering, the
amount of our outstanding total debt will be approximately $56.5 million, based
on the amount of our outstanding indebtedness as of August 22, 2000. We will use
the increased borrowing capacity under our credit agreement, along with cash
flow from operations, to pursue exploitation, acquisition and exploration
activities and for general corporate purposes.

Our credit agreement terminates on April 4, 2003 and the entire unpaid
principal balance and accrued interest are due and payable on that date. At June
30, 2000, the average interest rate on borrowings under our credit agreement was
approximately 8.3% per annum. Approximately $50 million of the initial
borrowings under our credit agreement were used to pay the cash portion of the
purchase price in connection with the merger between Westport Oil and Gas and
EPGC and $105.5 million was used to refinance indebtedness under a previous
credit facility. The remainder of the borrowings under our credit agreement has
been used for working capital and general corporate purposes.

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

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 currently restricted under our credit agreement.

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<PAGE> 22

DILUTION

Our net tangible book value as of June 30, 2000 was approximately $318.9
million, or $10.33 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 June 30, 2000, other than to give effect to our sale of the
6,500,000 shares of common stock offered hereby and our net proceeds therefrom,
our as adjusted net tangible book value as of June 30, 2000 would have been
approximately $408.7 million, or $10.94 per share of common stock. This
represents an immediate increase in net tangible book value of $0.61 per share
to existing stockholders and an immediate dilution of $4.06 per share to
investors in this offering. The following table illustrates this dilution:

<TABLE>
<CAPTION>
PER SHARE
---------------
<S> <C> <C>
Initial public offering price............................... $15.00
Net tangible book value before this offering.............. $10.33
Increase attributable to new investors.................... 0.61
------
As adjusted net tangible book value after this offering..... 10.94
------
Dilution to new investors................................. $ 4.06
======
</TABLE>

The following table summarizes, on an as adjusted basis as of June 30,
2000, the differences between existing stockholders and investors in this
offering with respect to the number of shares of common stock purchased from us,
the total consideration paid and the average price per share paid, based on an
initial public offering price of $15.00 per share and 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.................... 30,869,419 82.6% $366,732,000 79.0% $11.88
New investors............................ 6,500,000 17.4 97,500,000 21.0 15.00
---------- ----- ------------ -----
Total.......................... 37,369,419 100.0% $464,232,000 100.0%
========== ===== ============ =====
</TABLE>

The table does not include 4,110,813 shares of common stock reserved for
issuance under our stock option plan, of which options in respect of 1,527,441
shares have been granted at a per share exercise price of $10.89. To the extent
any options under this plan are exercised in the future, there may be further
dilution to existing stockholders.

20
<PAGE> 23

CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2000. Our
capitalization is presented:

- on an actual basis; and

- on an as adjusted basis to give effect to:

- the sale by us of 6,500,000 shares of common stock in the offering at an
initial public offering price of $15.00 per share and 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>
JUNE 30, 2000
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS, EXCEPT
SHARE DATA)
<S> <C> <C>
Cash........................................................ $ 15,684 $ 15,684
======== ========
Short-term debt............................................. $ 667 $ 667
======== ========
LONG-TERM DEBT:
Credit agreement.......................................... $155,462 $ 65,701
-------- --------
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value (5,000,000 shares
authorized and no shares outstanding actual or as
adjusted).............................................. -- --
Common stock, $0.01 par value (70,000,000 shares
authorized, 30,869,419 shares outstanding actual and
37,369,419 shares outstanding as adjusted)............. 309 374
Additional paid-in capital................................ 366,423 456,119
Accumulated deficit....................................... (47,834) (47,834)
-------- --------
Total stockholders' equity................................ 318,898 408,659
-------- --------
Total capitalization.............................. $474,360 $474,360
======== ========
</TABLE>

21
<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 six-month periods ended June 30, 1999 and 2000 from our
unaudited consolidated financial statements, 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 six-month period ended June 30, 2000 are not
necessarily indicative of the results that we may achieve for the entire year.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------------------------ -------------------
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 $ 31,891 $ 77,548
Operating costs and
expenses:
Lease operating
expense................ 5,787 10,716 19,583 21,554 22,916 10,139 15,480
Production taxes......... 1,873 3,561 5,923 3,888 5,742 2,186 4,644
Exploration.............. 1,102 1,054 7,424 14,664 7,314 2,091 6,263
Depletion, depreciation
and amortization....... 5,888 8,325 23,659 36,264 25,210 16,309 22,576
Impairment of proved
properties............. -- 442 5,765 8,794 3,072 -- --
Impairment of unproved
properties............. -- -- 380 1,898 2,273 3 1,541
General and
administrative......... 1,184 2,655 5,316 5,913 5,297 2,995 6,587(1)
-------- -------- --------- --------- -------- -------- --------
Total operating
expenses........ 15,834 26,753 68,050 92,975 71,824 33,723 57,091
-------- -------- --------- --------- -------- -------- --------
Operating income
(loss).......... 3,612 8,388 (4,961) (41,470) 1,939 (1,832) 20,457
Other income (expense):
Interest expense......... (2,307) (2,774) (5,635) (8,323) (9,207) (4,577) (5,288)
Interest income.......... 116 313 309 403 489 215 375
Gain (loss) on sale of
assets -- net.......... -- 128 (13) -- 3,637 4,397 (11)
Other.................... 7 44 (54) 29 16 20 32
-------- -------- --------- --------- -------- -------- --------
Income (loss) before income
taxes.................... 1,428 6,099 (10,354) (49,361) (3,126) (1,777) 15,565
Benefit (provision) for
income taxes............. -- (2,289) 973 -- -- -- (4,959)
-------- -------- --------- --------- -------- -------- --------
Net income (loss).......... $ 1,428 $ 3,810 $ (9,381) $ (49,361) $ (3,126) $ (1,777) $ 10,606
======== ======== ========= ========= ======== ======== ========
</TABLE>

22
<PAGE> 25

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------------------------ -------------------
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.................... 4,500 4,531 9,326 11,004 14,727 13,806 22,785
======== ======== ========= ========= ======== ======== ========
Diluted.................. 4,500 4,531 9,326 11,004 14,727 13,806 22,975
======== ======== ========= ========= ======== ======== ========
NET INCOME (LOSS) PER
COMMON SHARE:
Basic.................... $ 0.32 $ 0.84 $ (1.01) $ (4.49) $ (0.21) $ (0.13) $ 0.47
======== ======== ========= ========= ======== ======== ========
Diluted.................. $ 0.32 $ 0.84 $ (1.01) $ (4.49) $ (0.21) $ (0.13) $ 0.46
======== ======== ========= ========= ======== ======== ========
SUPPLEMENTAL NET INCOME PER
COMMON SHARE(2):
Basic.................... $ 0.17 $ 0.44
======== ========
Diluted.................. $ 0.17 $ 0.44
======== ========
OTHER FINANCIAL DATA:
Adjusted EBITDA(3)......... $ 10,725 $ 18,694 $ 32,509 $ 20,582 $ 43,950 $ 21,203 $ 51,233
Net cash provided by
operating activities..... 12,144 15,921 24,146 7,622 21,279 451 18,847
Net cash provided by (used
in) investing
activities............... (70,279) (24,040) (150,441) (113,019) 17,981 22,548 (71,971)
Net cash provided by (used
in) financing
activities............... 62,200 13,735 126,675 104,667 (29,933) (22,767) 49,333
Capital expenditures....... 70,279 24,023 153,791 113,008 14,005 2,200 71,749
BALANCE SHEET DATA (AS OF
PERIOD END):
Cash....................... $ 4,881 $ 10,497 $ 10,878 $ 10,148 $ 19,475 $ 10,380 $ 15,684
Working capital
(deficit)................ (1,490) 7,797 4,296 (30,993) 12,837 (1,656) 36,559
Total assets............... 95,838 117,597 245,394 302,302 271,477 270,470 514,067
Total long-term debt....... 26,625 25,462 92,128 121,333 105,462 100,667 155,462
Total debt................. 34,125 26,795 93,462 153,128 106,795 113,962 156,129
Stockholders' equity....... 55,596 80,471 131,098 126,737 140,011 141,360 318,898
</TABLE>

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

(2) Supplemental net income per common share gives effect to the issuance of
6,500,000 shares of common stock in connection with this offering and the
application of the net proceeds from this offering to repay a portion of the
outstanding debt.

UNAUDITED PRO FORMA FINANCIAL STATEMENTS
OF WESTPORT RESOURCES CORPORATION

On April 7, 2000, Westport Oil and Gas merged with EPGC. The merger
resulted 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, and Westport Resources Corporation began consolidating the
results of EPGC with the results of Westport Oil and Gas as of April 7, 2000.

The following unaudited pro forma condensed consolidated statements of
operations for the year ended December 31, 1999 and the six months ended June
30, 2000 adjust the historical financial information of Westport Oil and Gas to
reflect the merger with EPGC. The pro forma statements of operations were
prepared as if the merger 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 Westport Resources
Corporation 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 merger been consummated on the date
indicated or which may occur in the future.

24
<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................................................. 14,727 15,237(F) 29,964
======= ======= ========
Diluted............................................... 14,727 15,374(F) 30,101
======= ======= ========
Net income (loss) per common share:
Basic................................................. $ (0.21) $ 0.32
======= ========
Diluted............................................... $ (0.21) $ 0.31
======= ========
</TABLE>

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

25
<PAGE> 28

WESTPORT RESOURCES CORPORATION

UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2000
(IN THOUSANDS, EXCEPT PER SHARE DATA)

<TABLE>
<CAPTION>
HISTORICAL
WESTPORT OIL PRO FORMA
AND GAS ADJUSTMENTS PRO FORMA
------------ ----------- ---------
<S> <C> <C> <C>
Revenues................................................ $77,548 $18,932(A) $96,480
------- ------- -------
Operating costs and expenses:
Lease operating expense............................... 15,480 1,215(A) 16,695
Production taxes...................................... 4,644 -- 4,644
Exploration........................................... 6,263 -- 6,263
Depletion, depreciation and amortization.............. 22,576 10,126(B) 32,702
Impairment of unproved properties..................... 1,541 -- 1,541
General and administrative............................ 6,587 702(C) 7,289
------- ------- -------
Total operating expenses...................... 57,091 12,043 69,134
------- ------- -------
Operating income.............................. 20,457 6,889 27,346
------- ------- -------
Other income (expense):
Interest expense...................................... (5,288) (1,023)(D) (6,311)
Interest income....................................... 375 -- 375
Loss on sale of assets -- net......................... (11) -- (11)
Other................................................. 32 -- 32
------- ------- -------
Income before income taxes.............................. 15,565 5,866 21,431
Provision for income taxes.............................. (4,959) (2,542)(E) (7,501)
------- ------- -------
Net income.............................................. $10,606 $ 3,324 $13,930
======= ======= =======
Weighted average number of common shares outstanding:
Basic................................................. 22,785 8,082(F) 30,867
======= ======= =======
Diluted............................................... 22,975 8,082(F) 31,057
======= ======= =======
Net income per common share:
Basic................................................. $ 0.47 $ 0.45
======= =======
Diluted............................................... $ 0.46 $ 0.45
======= =======
</TABLE>

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

26
<PAGE> 29

WESTPORT RESOURCES CORPORATION

NOTES TO UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS

(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 additional employees hired by Westport in connection with its
Gulf of Mexico expansion efforts.

(D) Adjustment to reflect additional interest expense related to debt incurred
to finance the merger between Westport Oil and Gas and EPGC. The interest
rate used was Westport Oil and Gas' effective rate of 8.1% at April 7,
2000. Based on outstanding indebtedness at June 30, 2000 of $155.5
million, a 1/8 percentage point increase or decrease in interest rates
would affect future annual interest payments by approximately $0.2
million.

(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
15,236,152 shares of Westport common stock in connection with the merger
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.

27
<PAGE> 30

WESTPORT RESOURCES CORPORATION

SUPPLEMENTAL PRO FORMA INFORMATION RELATED TO OIL AND GAS ACTIVITIES

Estimates of total proved and proved developed reserves for Westport Oil
and Gas at December 31, 1997, 1998 and 1999 were prepared by Ryder Scott.
Estimates of total proved and proved developed reserves for EPGC at December 31,
1997 and 1998 were prepared by EPGC's petroleum engineers and audited by
Netherland, Sewell. At December 31, 1999, the EPGC report was prepared by
Netherland, Sewell.

PRO FORMA QUANTITIES OF OIL AND NATURAL GAS RESERVES (UNAUDITED)

The following table presents estimates of Westport Oil and Gas and EPGC pro
forma net proved and proved developed oil and natural gas reserves:

<TABLE>
<CAPTION>
1997 1998 1999
------------------------ ------------------------ ------------------------
OIL (Mbbls) GAS (Mmcf) OIL (Mbbls) GAS (Mmcf) OIL (Mbbls) GAS (Mmcf)
----------- ---------- ----------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Total proved reserves
Beginning of
year............ 20,861 25,607 31,348 113,717 29,057 187,232
Production......... (3,446) (15,893) (4,102) (26,883) (4,061) (36,413)
Revisions of
previous
estimates....... (3,504) 1,270 (2,623) 1,423 13,162 29,153
Extensions,
discoveries and
other
additions....... 4,581 19,377 3,543 29,815 1,849 66,189
Purchases of
reserves in
place........... 12,856 83,356 1,212 70,395 -- --
Sales of reserves
in place........ -- -- (321) (1,235) (2,898) (14,273)
------ ------- ------ ------- ------ -------
End of year........ 31,348 113,717 29,057 187,232 37,109 231,888
====== ======= ====== ======= ====== =======
Proved developed
reserves........... 28,179 84,591 23,495 156,095 31,911 174,753
====== ======= ====== ======= ====== =======
</TABLE>

STANDARDIZED MEASURE OF DISCOUNTED PRO FORMA 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................................. $ 758,066 $ 607,508 $1,348,467
Future production costs........................... (279,241) (245,981) (410,944)
Future development costs.......................... (53,679) (71,482) (102,577)
--------- --------- ----------
Future net cash flows before tax.................. 425,146 290,045 834,946
Future income taxes............................... (48,771) (4,766) (152,756)
--------- --------- ----------
Future net cash flows after tax................... 376,375 285,279 682,190
Annual discount at 10%............................ (103,247) (88,591) (196,095)
--------- --------- ----------
Standardized measure of discounted future net cash
flows........................................... $ 273,128 $ 196,688 $ 486,095
========= ========= ==========
</TABLE>

28
<PAGE> 31

WESTPORT RESOURCES CORPORATION

SUPPLEMENTAL PRO FORMA INFORMATION RELATED TO OIL AND GAS ACTIVITIES

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

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------
1997 1998 1999
-------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and natural gas sales, net of production
costs............................................. $(65,491) $ (61,291) $(108,853)
Net changes in anticipated prices and production
cost.............................................. (97,411) (150,367) 196,419
Extensions and discoveries, less related costs...... 54,451 51,959 103,019
Changes in estimated future development costs....... (1,090) 21,897 2,309
Previously estimated development costs incurred..... 538 6,865 6,175
Net change in income taxes.......................... 7,720 12,687 (51,609)
Purchase of minerals in place....................... 193,014 41,513 --
Sales of minerals in place.......................... -- (2,301) (800)
Accretion of discount............................... 19,394 27,499 20,337
Revision of quantity estimates...................... (7,082) (8,207) 137,879
Changes in production rates and other............... (1,483) (16,694) (15,469)
-------- --------- ---------
Changes in standardized measure................... $102,560 $ (76,440) $ 289,407
======== ========= =========
</TABLE>

29
<PAGE> 32

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 merger with EPGC pursuant to
which Westport Oil and Gas acquired the Gulf of Mexico properties of Equitable
Production Company that were held by EPGC. In connection with this merger, we
issued 15.2 million shares of common stock, paid cash of $50.0 million and
assumed liabilities of $1.8 million. We increased our proved reserves by 129.8
Bcfe and our Gulf of Mexico leasehold by 157,000 net acres. On October 15, 1998,
Westport Oil and Gas acquired an undivided 31% interest in the individual assets
and liabilities of Total Minatome Corporation, which consist primarily of
working interests in oil and natural gas properties, 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 64 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 82 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 approximately $84.0 million from Conoco,
Chevron, Mobil, Koch and others establishing its operations and reserve base in
the Rocky Mountain and West Texas/Mid-Continent areas.

We incurred net losses of $9.4 million, $49.4 million and $3.1 million in
1997, 1998 and 1999, respectively. 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 significantly increased.
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, 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 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
30
<PAGE> 33

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,
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," 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 discounted future net revenues based on escalated
prices. Impairments for the years ended December 31, 1999, 1998 and 1997 were
calculated based on the following prices: oil prices per barrel of $20.84,
$13.00 and $17.77, respectively; and natural gas prices per Mcf of $2.36, $1.95
and $1.81, respectively. Oil prices were escalated annually at 2.5%, 2.0% and
3.0% in 1999, 1998 and 1997, respectively. Gas prices were escalated annually at
2.5%, 3.0% and 3.0% in 1999, 1998 and 1997, respectively. Estimates of declining
production were based on estimates by independent reserve engineers and
estimated operating costs and severance taxes were based on past experience.
Operating and future development costs were escalated annually at 2.5%, 3.0% and
3.0% in 1999, 1998 and 1997, respectively. Reserve categories used in the
impairment analysis for all periods considered all categories of proven reserves
and probable and possible reserves, which were risk-adjusted based on our
drilling plans and history of successfully developing those types of reserves.
Estimates of reserve volumes for each reserve category for each year were
prepared by independent reserve engineers.

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
and our intent to pursue additional exploration opportunities on such property.

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 merger
between EPGC and Westport Oil and Gas resulted 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 merger, 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 merger 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 our results of
operations for the six months ended June 30, 2000 and 1999, a comparison of the
results of operations of Westport Oil and Gas on a stand-alone basis for the
years ended December 31, 1999, 1998 and 1997, a comparison of the revenues and
lease operating expense of EPGC for the years ended December 31, 1999, 1998 and
1997 and the three months ended March 31, 2000 and 1999, and a presentation of
pro forma revenues and expenses for the year ended December 31, 1999 and the
first half of 2000, assuming the merger between Westport Oil and Gas and EPGC
was consummated on January 1, 1999.

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<PAGE> 34

Six Months Ended June 30, 2000 Compared to Six Months Ended June 30, 1999

REVENUES. Oil and natural gas revenues for the six months ended June 30,
2000 increased by $45.6 million, or 143%, from $31.9 million to $77.5 million.
The EPGC merger accounted for $25.5 million of the increase and the remaining
increase resulted from increases of 113% and 80% in realized oil and natural gas
prices, respectively. The increase of 7.0 Bcfe in production volumes from 16.7
Bcfe to 23.7 Bcfe was primarily due to 7.2 Bcfe from the acquired EPGC
properties, partially offset by sales of oil and natural gas properties in 1999.
Hedging transactions had the effect of reducing oil and natural gas revenues by
$8.5 million, or $0.36 per Mcfe, in the first six months of 2000. 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 6.1 Bcfe
to 6.7 Bcfe 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
six months ended June 30, 2000 would have been $96.5 million and 30.5 Bcfe,
respectively.

LEASE OPERATING EXPENSE. Lease operating expense for the six months ended
June 30, 2000 increased by $5.4 million, or 53%, from $10.1 million to $15.5
million. The EPGC merger accounted for $2.1 million of the increase and
additional well reactivations and well maintenance work performed during the six
months ended June 30, 2000 after the recovery of oil and natural gas prices in
the second half of 1999 accounted for the balance. On a per Mcfe basis, lease
operating expense increased from $0.61 to $0.65.

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 six months
ended June 30, 2000 would have been $16.7 million, or $0.55 per Mcfe.

PRODUCTION TAXES. Production taxes for the six months ended June 30, 2000
increased by $2.4 million, or 112%, from $2.2 million to $4.6 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 decreased from
6.8% to 5.4%. The decrease in production taxes as a percent of revenue is
primarily the result of the EPGC merger, which increased the number of offshore
properties that are not subject to production taxes.

EXPLORATION COSTS. Exploration costs increased $4.2 million, or 199%,
during the six months ended June 30, 2000, from $2.1 million to $6.3 million.
The increase was primarily attributable to 3-D seismic data purchased in the
Gulf of Mexico related to the EPGC merger and two unsuccessful exploratory wells
drilled during the six months ended June 30, 2000.

DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A) EXPENSE. DD&A expense
increased $6.3 million, or 38%, during the six months ended June 30, 2000 from
$16.3 million to $22.6 million. The EPGC merger caused the DD&A expense to
increase $10.3 million. The offsetting decline was attributable to an increase
in estimated proved reserves resulting from higher oil and natural gas prices at
June 30, 2000 as compared to June 30, 1999.

IMPAIRMENT OF UNPROVED PROPERTIES. During the six months ended June 30,
2000, we recognized unproved property impairments of $1.5 million, as a result
of an assessment of the exploration opportunities existing on such properties.
The $1.5 million consisted of $0.6 million for leases held
32
<PAGE> 35

offshore, $0.4 million for leases held in Kansas and $0.5 million for various
leases held in Louisiana and Wyoming. We did not recognize any unproved property
impairments during the six months ended June 30, 1999.

GENERAL AND ADMINISTRATIVE (G&A) EXPENSE. G&A expense increased $3.6
million, or 120%, during the six months ended June 30, 2000, from $3.0 million
to $6.6 million. The increase was the result of a one-time compensation expense
of $3.4 million related to the repurchase of employee stock options recorded
during the six months ended June 30, 2000.

OTHER INCOME (EXPENSE). Other income (expense) for the six months ended
June 30, 2000 was ($4.9 million) compared to $0.1 million for the six months
ended June 30, 1999. Interest expense of $4.6 million recorded in the six months
ended June 30, 1999 was offset by a $4.4 million gain on the sale of assets.
Interest expense increased $0.7 million from $4.6 million to $5.3 million
primarily as a result of $50.0 million in additional borrowings relating to the
EPGC merger and an increase in interest rates.

INCOME TAXES. We recorded income tax expense of $5.0 million for the six
months ended June 30, 2000 and no income tax expense or benefit for the six
months ended June 30, 1999. The difference between the income tax expense
(benefit) for those periods and the amounts that would be calculated by applying
statutory income tax rates to income (loss) before income taxes is due primarily
to the decrease or increase in our deferred tax asset valuation allowance.

NET INCOME (LOSS). Net income for the six months ended June 30, 2000 was
$10.6 million compared to a net loss of $1.8 million for the six months ended
June 30, 1999. The variance was primarily attributable to an increase in
revenues of $45.6 million, partially offset by an increase of $23.4 million in
operating expenses.

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 29.0 Bcfe to 33.1 Bcfe 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 22.5 Bcfe to 27.7 Bcfe 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 60.8 Bcfe, 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.

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<PAGE> 36

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.

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. The impairment recorded in 1999 was the result of a decrease in
risk adjusted probable reserves for the Ward Estes lease located in West Texas,
which were subsequently assigned to the operator of the lease in exchange for
existing producing property equipment and infrastructure owned by the operator.
The impairments recorded in 1998 were as follows: $4.9 million resulting from
depressed oil prices for certain long-lived oil properties located primarily in
the Rocky Mountains, $2.5 million resulting from depressed natural gas prices
for certain natural gas properties located in the Mid-Continent and $1.4 million
based on the results of unsuccessful development drilling in the Mid-Continent.

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. In 1999, $1.3 million and $0.9 million were
impaired for costs associated with a prospect off the coast of Argentina and
leases held in North Dakota and Wyoming, respectively. In 1998, $1.7 million and
$0.2 million were impaired for leases held in Michigan and North Dakota,
respectively.

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.

INCOME TAXES. We recorded no income tax benefit in 1999 and 1998 resulting
from losses incurred in those years. The difference between the income tax
benefit for those years and the amount that would be calculated by applying
statutory income tax rates to loss before income taxes is due primarily to
deferred tax asset valuation allowances recorded in those years. As of December
31, 1999, we had a net deferred tax asset of $22.4 million, including net
operating loss carryforwards of $17.4 million. As a result of our history of net
losses, we have recorded a valuation analysis equal to our net deferred tax
asset.

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<PAGE> 37

NET LOSS. Net loss for 1999 was $3.1 million compared to $49.4 million for
1998. The decrease in net loss was primarily attributable to an increase in
revenues of $22.3 million and decreases in exploration costs of $7.4 million and
DD&A expense of $11.1 million.

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 23.9
Bcfe to 29.0 Bcfe 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 12.6 Bcfe to 22.5 Bcfe 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.

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. The impairments recorded in 1998 were as follows: $4.9 million
resulting from depressed oil prices for certain long-lived oil properties
located primarily in the Rocky Mountains, $2.5 million resulting from depressed
natural gas prices for certain natural gas properties located in the West
Texas/Mid-Continent area and $1.4 million based on the results
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<PAGE> 38

of unsuccessful development drilling in the West Texas/Mid-Continent. The
impairment recorded in 1997 was the result of depressed oil prices for certain
long-lived oil assets located in the Rocky Mountains.

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 the affected properties. In 1998, $1.7 million and $0.2 million were
impaired for leases held in Michigan and North Dakota, respectively. In 1997,
$0.4 million was impaired for leases held in North Dakota.

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.

INCOME TAXES. We recorded no income tax benefit or expense in 1998 and a
$1.0 million tax benefit in 1997 resulting from losses incurred in those years.
The difference between the income tax benefit for those years and the amount
that would be calculated by applying statutory income tax rates to loss before
income taxes is due primarily to deferred tax asset valuation allowances
recorded in those years. As of December 31, 1998, we had a net deferred tax
asset of $21.2 million, including net operating loss carryforwards of $16.0
million. As a result of our history of net losses, we have recorded a valuation
allowance equal to our net deferred tax asset.

NET LOSS. Net loss for 1998 was $49.4 million compared to $9.4 million for
1997. The increase in net loss was primarily attributable to a decrease in
revenues of $11.6 million and increases in exploration costs of $7.3 million and
DD&A expense of $12.6 million.

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 $18.8 million for the six months
ended June 30, 2000 compared to $0.5 million for the six months ended June 30,
1999. The operating cash flow in the six month period increased compared to the
prior period due to the increase in commodity prices and as a result of the
merger with EPGC. Cash flow from operating activities increased $13.7 million
from $7.6 million for 1998 to $21.3 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 was $72.0 million for the six months
ended June 30, 2000 compared to cash flow generated from investing activities of
$22.6 million for the six months ended June 30, 1999. Investing activities for
the six months ended June 30, 2000 include capital expenditures of $71.7
million, primarily resulting from the merger with EPGC, compared to capital
expenditures of $2.2 million offset by proceeds from sales of properties of
$24.3 million for the six months ended June 30, 1999. Cash flow generated from
investing activities was $18.0 million for 1999 compared to cash flow used in
investing activities of $113.0 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 $14.0 million in additions to oil and natural
gas properties. Cash used in 1998 related to acquisitions and exploitation and
exploration activities.

Net cash generated from financing activities was $49.3 million for the six
months ended June 30, 2000 compared to net cash used in financing activities of
$22.8 million for the six months ended June 30, 1999. Financing activities for
the six months ended June 30, 2000 reflect borrowings of $50.0 million utilized
to consummate the merger with EPGC, compared to repayments of long-term debt of
$39.2 million made in the six months ended June 30, 1999, offset by proceeds of
$16.4 million from the sale of common stock. Cash flow used in financing
activities of $29.9 million for 1999 compared to cash
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<PAGE> 39

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.

We generated Adjusted EBITDA of $51.2 million, $44.0 million, $20.6 million
and $32.5 million for the six months ended June 30, 2000 and years ended
December 31, 1999, 1998 and 1997, respectively. The increase in Adjusted EBITDA
from 1998 through the six months ended June 30, 2000 is indicative of the
successful implementation of our reserve growth strategy along with our focus on
maintaining efficient operations with a low cost structure, coupled with an
increase in commodity prices. While we believe that Adjusted EBITDA may provide
additional information with respect to our ability to meet our future debt
service, capital expenditures and working capital requirements, certain
functional or legal requirements of our business may require us to utilize our
available funds for other purposes.

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. Our properties, which have been
pledged as collateral securing outstanding indebtedness under our credit
agreement, could be foreclosed upon in the event of our default thereunder. 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 August 22, 2000 were $145.5
million. Pro forma for application of our net proceeds from the offering to
repay indebtedness under the credit agreement, as of August 22, 2000, the
borrowings under the credit agreement would have been $55.7 million and the
amount available for borrowings under the credit agreement would have been
$144.3 million. The credit agreement contains various covenants and restrictive
provisions, including with respect to the following matters:

- incurring other indebtedness;

- liens on our properties or assets;

- hedging contracts;

- mergers and issuances of securities;

- the sale of any of our material assets or properties;

- dividends and redemptions;

- investments and new businesses;

- credit extensions;

- transactions with affiliates; and

- prohibited contracts.

In addition to these non-financial covenants, our 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 the preceding four
consecutive fiscal quarters, beginning with the fiscal quarter ended March 31,
2000, of not less than 2.5 to 1.0. As of June 30, 2000, we were in compliance
with all credit agreement covenants. Our credit

37
<PAGE> 40

agreement contains various events of default, upon the occurrence of which all
of our obligations under our credit agreement become immediately due and
payable. The events of default include, among others:

- failure to pay any obligation under our credit agreement when due and
payable;

- failure to duly observe, perform or comply with certain covenants,
agreements or provisions of our credit agreement;

- a case relating to us being brought under any bankruptcy, insolvency or
similar law now or hereafter in effect;

- a change of control of Westport;

- any material adverse change; and

- both Donald D. Wolf ceasing to act as our chief executive officer and
chairman of the board and Barth E. Whitham ceasing to act as our chief
operating officer and president.

Any increases in the interest rates under our credit agreement 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
interest rate 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 10% increase or decrease in interest
rates 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.

Capital expenditures for 1999 included $3.7 million for exploitation and
$10.3 million for exploration. Approximately $75 million of our capital
expenditure budget for 2000 is allocated for exploitation and approximately $35
million allocated for exploration. As of June 30, 2000, we have spent
approximately $38 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.
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 and 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 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.

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<PAGE> 41

Through June 30, 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 $14.2 million to terminate the
existing arrangements on June 30, 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 1,080,473 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 at the end
of each fiscal quarter 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 measured at the end of each fiscal quarter
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 measured at the end of each fiscal quarter
after the award vests will be recognized immediately.

39
<PAGE> 42

BUSINESS AND PROPERTIES

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. We operate over 73% of the net present
value of our reserves. We finance our exploitation, exploration and acquisition
activities through cash flows from operations and through borrowings under our
credit agreement. Set forth below is summary information concerning average
daily production during the second quarter of 2000 and wells, reserves and net
present value as of June 30, 2000 in our major areas of operations. In the
information set forth below, "gross" refers to the total acres or wells in which
we have a working interest and "net" refers to gross acres or wells multiplied
by our working interest in such acres or wells. The term "working interest"
refers to 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 cost of drilling and
production operations.

<TABLE>
<CAPTION>
SECOND QUARTER
2000 AVERAGE AS OF JUNE 30, 2000
NET DAILY --------------------------------------------------------------------------------
PRODUCTION PROVED RESERVE QUANTITIES NET PRESENT VALUE
----------------- 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............. 90.3 52% 35.6 5.9 117.7 0.3 154.8 $426.8 45%
Rocky Mountains............ 58.8 34 347.7 24.3 58.6 0.0 204.4 345.3 36
West Texas/Mid-Continent... 11.2 7 356.8 7.7 15.8 0.0 62.2 117.5 12
Gulf Coast................. 11.7 7 33.2 0.1 36.9 0.0 37.7 68.7 7
----- --- ----- ---- ----- --- ----- ------ ---
Total.............. 172.0 100% 773.3 38.0 229.0 0.3 459.1 $958.3(1) 100%
===== === ===== ==== ===== === ===== ====== ===
</TABLE>

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

GULF OF MEXICO

The Gulf of Mexico represented 45% of our net present value as of June 30,
2000 and contributed 52% of our second quarter 2000 production. We have
interests in 259,681 developed and 360,628 undeveloped gross acres in the Gulf
of Mexico and in 131 gross producing wells (approximately 36 net). The average
net daily production for the second quarter of 2000 was 90 Mmcfe. We had 155
Bcfe of proved reserves in the Gulf of Mexico at June 30, 2000.

In addition to a solid production base with numerous exploitation
opportunities within our developed acreage, the Gulf of Mexico provides us with
moderate-risk exploration targets. We currently 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 3-D seismic data covering over
10,000 square miles (1,460 blocks) and 2-D seismic data covering 150,000 linear
miles within the Gulf of Mexico. Our material licenses of seismic data are
generally for terms of twenty years or more. As is industry practice, many of
our leasehold interests are temporary in nature and are held by payment of delay
rentals or by production. We are party to standard industry operating agreements
in connection with our non-operated properties. Under the terms of these
agreements, we can withhold our consent to certain capital expenditures and opt
instead to pay a specified penalty out of production, if any. We have had recent
discoveries on 10 blocks, five of which are producing and two of which we plan
to put on production in the second half of 2000. We subsequently sold our
interest in one of these blocks and will continue exploitation on the remaining
two blocks.

West Cameron 180/198. The West Cameron 180/198 complex consists 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 trillion cubic
feet of natural gas,

40
<PAGE> 43

or Tcf, and 10 million barrels of oil, or Mmbbl, 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 side-tracked an additional well, increasing the daily net
production in the second quarter of 2000 to 55 Mmcfe. As of June 30, 2000, we
had 93 Bcfe of proved reserves in the complex. As of June 30, 2000, we operated
14 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, two additional development wells are
planned and three to four wells are planned for 2001. A number of exploratory
locations have also been identified, with 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 second quarter of 2000 of
15 Mmcfe. As of June 30, 2000, we had 7 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. We operate five gross (2.5 net) wells with an average
net daily production in the second quarter of 2000 of 7 Mmcfe. As of June 30,
2000, we had 12 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. In the discussion below,
the term "non-operated working interest" refers to an interest in an oil and
natural gas lease or unit, the owner of which does not have operating rights by
reason of an operating agreement with the operator. The operator is the
individual or company responsible for the exploration, exploitation and
production of an oil or natural gas well or lease.

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 installed facilities and
commenced production in June 2000. Initial gross production was 4 Mmcfe/d
(approximately 1.7 Mmcfe/d net). 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
approximately 30 miles offshore in 50 feet of water. We operate the field
with a working interest of 50% and installed facilities and commenced
production in July 2000. Initial gross production was 8 Mmcfe/d
(approximately 3.3 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
approximately 120 miles offshore in 290 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.

41
<PAGE> 44

- High Island A-530. In 1999, this field was discovered, which is located
approximately 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).

- Grand Isle 45. In early 2000, new reserves were discovered in this
existing field, which is located approximately 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).

- Vermilion 336. This field is located approximately 90 miles offshore in
229 feet of water and was discovered in the fourth quarter of 1999. 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. This reservoir within the West Cameron 180/198 complex
is located approximately 30 miles offshore in 47 feet of water and was
discovered in 2000. 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. This field is located approximately 48 miles offshore in
275 feet of water and was discovered in the first half of 2000. We have a
non-operated 21% working interest in the well. A second well was recently
drilled and we plan to install facilities and commence production in
2001.

- Vermilion 408. This field is located approximately 110 miles offshore in
400 feet of water and was discovered in 1999. 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). A second well will be drilled in this
block in the second half of 2000. We anticipate installing facilities in
2001 and commencing production in early 2002.

- Mississippi Canyon 773. This field is located approximately 71 miles
offshore in 5,600 feet of water and was discovered in the fourth quarter
of 1999. An appraisal well was completed in the second quarter of 2000.
In the third quarter of 2000, we sold our 4% non-operated working
interest in this field.

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

<TABLE>
<CAPTION>
CURRENT TARGET NET ESTIMATED
WORKING WORKING OPERATED/ WATER WELL
PROSPECT LOCATION INTEREST INTEREST(1) NON-OPERATED DEPTH COSTS(2)
----------------- -------- ----------- ------------ ------ -------------
(%) (%) (FEET) (MILLIONS)
<S> <C> <C> <C> <C> <C>
East Cameron 104............................. 60 60 Operated 66 $1.3
Eugene Island 45A-2.......................... 60 60 Operated 17 1.4
Eugene Island 45C............................ 60 60 Operated 17 0.7
Eugene Island 45E-1.......................... 60 60 Operated 17 1.2
Grand Isle 103............................... 20 20 Non-operated 275 1.0
Grand Isle 106............................... 20 20 Non-operated 275 1.1
Mississippi Canyon 322....................... 50 25 Non-operated 700 0.7
Mississippi Canyon 489....................... 30 20 Non-operated 2,100 1.7
Ship Shoal 314/325........................... 100 50 Operated 311 1.8
Ship Shoal 86................................ 40 40 Non-operated 25 1.2
South Timbalier 293/306...................... 60 40 Operated 325 1.3
Vermilion 236................................ 50 50 Non-operated 128 1.2
Vermilion 54 Deep............................ 50 33 Non-operated 30 1.6
Vermilion 54 Shallow......................... 50 33 Non-operated 30 0.6
Vermilion 408-2.............................. 25 25 Non-operated 400 1.0
</TABLE>

42
<PAGE> 45

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

(1) Target working interest is our anticipated ownership interest at the time
the well is drilled, which we intend to achieve through the sale of a
portion of our current working interest.

(2) Based on target working interest.

ROCKY MOUNTAINS

The Rocky Mountain region represented 36% of our net present value as of
June 30, 2000 and contributed 34% of our second quarter 2000 production. We have
interests in 456,501 developed and 86,779 undeveloped gross acres in the region
and in 1,411 gross producing wells (approximately 348 net). The average daily
net production in the second quarter of 2000 was 59 Mmcfe. We had 204 Bcfe of
proved reserves in the Rocky Mountain region at June 30, 2000.

The majority of the net 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 91,021 developed and 59,867 undeveloped
gross acres in North Dakota and in 280 gross producing wells (approximately 148
net). We operate 223 of these gross wells. The average net daily production in
the second quarter of 2000 was 24 Mmcfe. We had 78 Bcfe of proved reserves at
June 30, 2000. 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 14
gross (approximately seven 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 2.3 Mmbbl (14 Bcfe) of proved
reserves in this area at June 30, 2000.

- 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 injection wells,
which are used to place liquids or gases into the producing zone to
assist in maintaining reservoir pressure and enhancing recoveries, and
drilled two horizontal wells. One of the horizontal 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 four net) wells. We utilize
high pressure air injection as the secondary recovery method, which
refers to an artificial method or process used to restore or increase
production from

43
<PAGE> 46

a reservoir after the primary production by the natural producing
mechanism and reservoir pressure has experienced partial depletion. 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 237,344 developed and 20,818 undeveloped
gross acres in the region and in 532 gross producing wells (approximately 184
net). We operate 193 of these gross wells. The average daily net production in
the second quarter of 2000 was 31 Mmcfe. We had 120 Bcfe of proved reserves in
this area at June 30, 2000. 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 31 Bcfe of proved reserves in this basin at June
30, 2000. Our most valuable onshore property based on net present 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 data, 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 440 gross producing wells
(approximately 140 net). We had 60 Bcfe of proved reserves in this basin
at June 30, 2000. In 2000, we plan to continue our coalbed methane
drilling in the Bonepile area and initiate an alkaline surfactant polymer
(ASP) flood in our Mellott Ranch field. An ASP flood is a tertiary
recovery technique that injects a mixture of chemicals into the reservoir
to aid in the recovery of previously bypassed oil, thus increasing the
ultimate produced reserves.

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. In 1999 and the first half of
2000, we have drilled 71 wells and gross production on August 9, 2000 was
over 17 Mmcf/d (approximately 7.4 Mmcf/d net) of gas from 50 wells, for an
average of 340 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 plan to drill an additional 35 to 40 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.

We have installed an ASP flood facility in our 100% owned and operated
Mellott Ranch field. ASP floods have been successfully implemented in two
fields near Mellott Ranch. Based on field size and modeling of reservoir
characteristics, we believe that we can achieve recovery increases as a
result of applying ASP technology.

44
<PAGE> 47

- Greater Green River Area. We have interests in 66 gross producing wells
(approximately 18 net). We operate 14 of these gross wells. We had 28
Bcfe of proved reserves in this area at June 30, 2000. 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, which refers to the technique
of improving a well's production or injection rates by pumping a mixture
of fluids into the formation and rupturing the rock, thereby creating an
artificial channel. Through June 30, 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 net present value
as of June 30, 2000 and contributed 7% of our second quarter 2000 production. We
have an interest in 49,003 developed and 53,580 undeveloped gross acres and in
1,347 gross producing wells (approximately 357 net). The average net daily
production in the second quarter of 2000 was 11 Mmcfe. We had 62 Bcfe of proved
reserves in this area at June 30, 2000. Our West Texas/Mid-Continent region
consists primarily of properties in Texas, Oklahoma and Kansas, with reserves
concentrated in the Permian and Anadarko basins.

West Texas. We own interests in 1,235 gross producing wells (approximately
297 net). We had 44 Bcfe (7.3 Mmboe) of proved reserves in this area at June 30,
2000. 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 net
present 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 half 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 112 gross producing wells
(approximately 60 net). We had over 18 Bcfe of proved reserves in this area at
June 30, 2000. We operate our principal properties in Oklahoma and Kansas, which
include the 12 producing-well East Harmon Waterflood Unit in Oklahoma, a six
producing-well waterflood in Oklahoma and a 13 producing-well secondary recovery
project in Kansas.

GULF COAST

The Gulf Coast represented 7% of our net present value as of June 30, 2000
and contributed 7% of our second quarter 2000 production. We have interests in
74,016 developed and 4,104 undeveloped gross acres in the Gulf Coast and in 352
gross producing wells (approximately 33 net). The average net daily production
in the second quarter of 2000 was 12 Mmcfe. We had 38 Bcfe of proved reserves in
the Gulf Coast at June 30, 2000.

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 over 100 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 2
Bcf. From our acquisition in October 1998 through June 30, 2000, we have
participated in 36 wells, of which 33 were successful. In the remainder of 2000,
we plan to drill an additional 20 to 30 wells. Bypassed producing zones are
being completed in 40 existing wells. We anticipate drilling between 35 and 40
wells in this region in each of the next three years.

45
<PAGE> 48

PROVED RESERVES

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

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
------------------------------ JUNE 30,
1997 1998 1999 2000
-------- -------- -------- --------
<S> <C> <C> <C> <C>
OIL (Mbbls)
Developed...................................... 25,588 20,323 29,489 31,678
Undeveloped.................................... 2,403 4,053 3,261 6,342
-------- -------- -------- --------
Total.................................. 27,991 24,376 32,750 38,020
======== ======== ======== ========
NATURAL GAS (Mmcf)
Developed...................................... 26,651 80,328 82,638 174,434
Undeveloped.................................... 1,925 19,957 36,531 54,605
-------- -------- -------- --------
Total.................................. 28,576 100,285 119,169 229,039
======== ======== ======== ========
NATURAL GAS LIQUIDS (Mbbls)
Developed...................................... 36 50 28 204
Undeveloped.................................... 0 0 0 125
-------- -------- -------- --------
Total.................................. 36 50 28 329
======== ======== ======== ========
TOTAL (MMCFE).................................... 196,737 246,840 315,838 459,135
======== ======== ======== ========
PRESENT VALUE ($ IN THOUSANDS)
Developed...................................... $146,985 $101,574 $300,328 $769,330
Undeveloped.................................... 8,423 9,710 48,771 188,958
-------- -------- -------- --------
Total.................................. $155,408 $111,284 $349,099(1) $958,288(1)
======== ======== ======== ========
STANDARDIZED MEASURE ($ IN THOUSANDS)(2)......... $153,550 $104,606 $322,435 $768,562
</TABLE>

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

(1) The difference in net present value from December 31, 1999 to June 30, 2000
resulted almost entirely from (i) the addition of 129.8 Bcfe of proved
reserves acquired in connection with the merger between Westport Oil and Gas
and EPGC and (ii) the increase in commodity prices used to determine net
present value (from $25.60 to $32.50 per bbl of oil and $2.30 to $4.33 per
Mmbtu of natural gas).

(2) The standardized measure is the value of the future after-tax net revenues
discounted at 10%. The difference between the net present value and the
standardized measure is the effect of income taxes discounted at 10%.

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 and Netherland, Sewell.

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.

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.
46
<PAGE> 49

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 generally accepted accounting principles, 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
--------------------------------------------- ------------------------
SIX
SIX MONTHS MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30, YEAR ENDED ENDED
--------------------------- --------------- DECEMBER 31, JUNE 30,
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 1,667 1,707 3,893 1,814
Natural gas (Mmcf)........ 5,265 8,101 13,313 6,661 13,330 36,413 19,185
NGL (Mbbls)(1)............ -- -- -- -- 29 168 65
Total Mmcfe............... 23,949 28,999 33,113 16,663 23,746 60,779 30,459
AVERAGE PRICES(2):
Oil (per bbl)............. $ 17.35 $ 10.79 $ 16.45 $12.42 $26.46 $16.69 $26.47
Natural gas (per Mcf)..... 1.71 1.68 2.06 1.68 3.02 2.19 2.89
NGL (per bbl)(1).......... -- -- -- -- 20.90 11.15 22.09
Total per Mcfe............ 2.63 1.77 2.47 1.92 3.62 2.41 3.45
AVERAGE COSTS (PER MCFE):
Lease operating expense... $ 0.82 $ 0.74 $ 0.69 $ 0.61 $ 0.65 $ 0.50 $ 0.55
General and
administrative.......... 0.22 0.20 0.16 0.18 0.28(3) 0.13 0.24(3)
Depletion, depreciation
and amortization........ 0.99 1.25 0.76 0.98 0.95 0.96 1.07
</TABLE>

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

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

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

47
<PAGE> 50

PRODUCING WELLS

The following table sets forth information at June 30, 2000 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>
GROSS NET AVERAGE
PRODUCING PRODUCING WORKING
WELLS WELLS INTEREST(1)
--------- --------- -----------
<S> <C> <C> <C>
Crude oil and liquids................................ 2,067 622.4 30.1%
Natural gas.......................................... 1,174 150.9 12.9
----- -----
Total................................................ 3,241 773.3
===== =====
</TABLE>

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

(1) Our weighted average working interest is 23.9%.

ACREAGE

The following table sets forth information at June 30, 2000 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............................................ 259,681 57,792
Rocky Mountain............................................ 456,501 169,764
West Texas/Mid-Continent.................................. 49,003 22,664
Gulf Coast................................................ 74,016 8,805
--------- -------
Total Developed........................................... 839,201 259,025
UNDEVELOPED:
Gulf of Mexico............................................ 360,628 191,577
Rocky Mountain............................................ 86,779 50,385
West Texas/Mid-Continent.................................. 53,580 18,308
Gulf Coast................................................ 4,104 757
--------- -------
Total Undeveloped......................................... 505,091 261,027
--------- -------
Total............................................. 1,344,292 520,052
========= =======
</TABLE>

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<PAGE> 51

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 half of 2000, we spudded 83 wells, of which 71 gross (23.5
net) wells have been completed as productive, nine gross (3.1 net) wells had
been plugged and abandoned and three gross offshore exploratory wells (0.7 net)
will be completed at a later date.

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 20%,
respectively. The sales to Equitable Energy, LLC were terminated on June 1,
2000.

COMPETITION

We compete with major and independent oil and natural gas companies.
Because oil and natural gas are commodity products that are sold by hundreds of
competitors, we cannot identify with certainty which of our competitors are
material competitors. 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

49
<PAGE> 52

explore for oil and natural gas prospects and to acquire additional properties
in the 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.
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<PAGE> 53

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, we can offer you 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 is 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.

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 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 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

51
<PAGE> 54

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.

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 elect not to 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.

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<PAGE> 55

EMPLOYEES

At June 30, 2000, we had 94 full-time employees and seven consultants. We
believe that our relationships with our employees are satisfactory. None of our
employees is 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> 56

MANAGEMENT

EXECUTIVE OFFICERS AND DIRECTORS

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

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Donald D. Wolf................... 57 Chairman, Chief Executive Officer and
Director
Barth E. Whitham................. 44 President, Chief Operating Officer and
Secretary
James H. Shonsey................. 49 Chief Financial Officer
Kenneth D. Anderson.............. 57 Vice President -- Accounting
Lynn S. Belcher.................. 47 Vice President -- Business Development
Brian K. Bess.................... 40 Vice President -- Engineering
Klein P. Kleinpeter.............. 48 Vice President and General Manager, Gulf
Coast
Alex M. Cranberg................. 45 Director
James M. Funk.................... 50 Director
Murry S. Gerber.................. 47 Director
Peter R. Hearl................... 49 Director
David L. Porges.................. 42 Director
Michael Russell.................. 50 Director
Randy Stein...................... 47 Director
William F. Wallace............... 61 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 August 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 from 1991 to August 1997. From 1987 to
1991, Mr. Shonsey served in various capacities, including director of
operations -- accounting for

54
<PAGE> 57

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 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 1991 as controller. For the
seven years prior to joining Westport Oil and Gas, he was 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.

Lynn S. Belcher, Vice President -- Business Development since April 2000.
Mr. Belcher joined Westport Oil and Gas in September 1996 as vice
president - land. He served in this position until June 1998 when he was named
vice president -- business development. Mr. Belcher 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. Mr. Belcher co-founded Focus Exploration, Inc. in 1985 and Peak Energy Co.
in 1992. Mr. Belcher served as vice president-land for Peak Energy Co. from June
1995 through September 1996. 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 May 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 February 1993
until May 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 merger between Westport
Oil and Gas and EPGC. He originally joined Equitable Production Company in
December 1996 as a consultant. Mr. Kleinpeter held various management positions,
including vice president production and engineering with CNG Producing Company
from 1985 to March 1996. Mr. Kleinpeter was an independent consultant from March
1996 through December 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.

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, where he has served since 1993. Mr. Cranberg was a director of Westport
Oil and Gas prior to its merger 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.

James M. Funk, Director since April 2000. Mr. Funk joined Equitable
Resources, Inc. as president, Equitable Production Company, in June 2000. Prior
to joining Equitable Production Company, Mr. Funk was an independent consultant
for J.M. Funk & Assoc., Inc. from February 1999 through June 2000. Prior to
this, Mr. Funk worked for 23 years at Shell Oil, where he held positions of
president, Shell Continental Companies (January 1998 through January 1999), vice
president, Shell Offshore, Inc. and general manager, Shelf E&P Business Unit
(October 1991 through December 1997), and chief executive officer of Shell
Midstream Enterprises, Inc. (April 1996 through December 1997). Mr. Funk is a
certified petroleum geologist and has a bachelor's 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.

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<PAGE> 58

Murry S. Gerber, Director since April 2000. Mr. Gerber is chairman,
president and chief executive officer of Equitable Resources, Inc. where he has
served since June 1998. 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 from November 1995 through June 1998. Prior to that,
he held various positions at Shell Oil, including treasurer from November 1994
through November 1995. Mr. Gerber also serves on the board of BlackRock, Inc.
Mr. Gerber holds a bachelor's degree in geology from Augustana College and a
master's degree in geology from the University of Illinois.

Peter R. Hearl, Director since July 2000. Mr. Hearl is executive vice
president of Tricon Restaurants International, formerly PepsiCo Restaurants
International. Mr. Hearl joined Tricon in 1991. During his tenure with Tricon,
Mr. Hearl has served in various senior management and executive positions
throughout Europe, Asia, Australia, the Middle East and Africa. Mr. Hearl also
serves on Tricon's Partners Council and is Tricon's senior representative for
joint venture businesses in Japan, Canada and Poland. Prior to joining Tricon,
Mr. Hearl worked for Exxon in Australia and the United States in a variety of
strategic planning, marketing, operational and senior management positions. He
serves as a director of Kentucky Fried Chicken Ltd. Japan. Mr. Hearl holds a
degree in commerce (economics) from the University of New South Wales and
studied management accounting at Adelaide University.

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 July 1998. Prior to joining Equitable
Resources, Inc., Mr. Porges was a managing director for Bankers Trust
Corporation, a financial services firm, from 1991 through July 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.

Michael Russell, 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 majority shareholder of Westport Resources. He was a director of
Westport Oil and Gas and served as its president from its inception through June
1996. He has been involved in the U.S. oil and natural gas industry for the past
20 years. Mr. Russell has worked for Dr. Richard J. Haas Partners for the past
24 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. Mr. Russell holds a bachelor of arts degree
in law and economics from Keele University in England and became a barrister of
law at College of Law in London. Mr. Russell was called to the bar at Lincoln's
Inn, London.

Randy Stein, Director since July 2000. Since July 1, 2000, Mr. Stein has
been a self-employed tax and business consultant. From November 1986 to June 30,
2000, Mr. Stein served as a principal at PricewaterhouseCoopers LLP, formerly
Coopers & Lybrand LLP, where he was in charge of the Denver tax practice with
responsibility for client service, business development and other operational
affairs. From 1980 through November 1986, Mr. Stein was an executive officer of
Petro Lewis Corporation, a Denver based energy company. Mr. Stein has over 25
years of experience in the energy industry providing accounting and tax
consulting, and has been involved in numerous mergers, acquisitions and initial
public offerings. Mr. Stein received a bachelor of science degree in accounting
from Florida State 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 has worked with Beacon Alliance since January 1996. Mr. Wallace was a
director of Westport Oil and Gas prior to the merger 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 from August 1995
through March 1996. He served as president, chief operating officer and director
of Plains Petroleum Co. from September 1994 to August 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

56
<PAGE> 59

Eastern Region, responsible for all exploration and producing activities onshore
and offshore throughout the eastern United States. Mr. Wallace received a
bachelor's degree from Middlebury College and a master of science degree from
Stanford University.

The executive officers named above hold such offices until their respective
successors have been duly elected and qualified or until their earlier
resignation or removal from office.

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 MEMBERS EXPIRATION OF TERM
----- ------- ------------------
<S> <C> <C>
Class 1......................................... James M. Funk 2001
William F. Wallace
Peter R. Hearl
Class 2......................................... David L. Porges 2002
Donald D. Wolf
Alex M. Cranberg
Class 3......................................... Murry S. Gerber 2003
Michael Russell
Randy Stein
</TABLE>

Pursuant to a shareholders' agreement dated March 9, 2000, ERI Investments,
Inc. and Westport Energy LLC each have the right to designate a total of four
directors. Following a qualified public offering, each of ERI Investments, Inc.
and Westport Energy LLC will have the right to designate three directors, one to
each class. In addition, the agreement provides that our then current chief
executive officer shall serve as a director. The number of directors a party may
designate is reduced if the ownership of the party is reduced below designated
thresholds. Of the current directors, Messrs. Hearl, Porges, Gerber and Funk
were designated by ERI Investments, Inc. and Messrs. Stein, Cranberg, Russell
and Wallace were designated by Westport Energy LLC. See "Certain Transactions."

COMMITTEES OF THE BOARD OF DIRECTORS

Our board of directors has established an audit committee and a
compensation committee.

Audit Committee

The audit committee currently consists of Messrs. Stein (chairman), Hearl
and Wallace. 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.

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<PAGE> 60

Compensation Committee

The compensation committee currently consists of Messrs. Wallace
(chairman), Stein and Cranberg. 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 4,500 shares of our common stock, which vests
annually over two years.

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<PAGE> 61

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 and (ii) 10% of the total annual salary and
bonus for such named executive officer in that year.

SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
LONG TERM
COMPENSATION
AWARDS
ANNUAL COMPENSATION ------------
---------------------------------------- SECURITIES
OTHER ANNUAL UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION SALARY ($) BONUS ($) COMPENSATION(1) OPTIONS COMPENSATION
--------------------------- ---------- --------- --------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Donald D. Wolf................. $220,631 $50,000 $13,117 308,250 --
Chairman, Chief Executive
Officer
Barth E. Whitham............... 196,181 33,000 12,533 98,100 --
President, Chief Operating
Officer, Secretary
Allan D. Keel(2)............... 152,381 36,684 -- -- --
Vice President -- Gulf of
Mexico Exploration
James H. Shonsey............... 153,181 11,945 -- 18,000 --
Chief Financial Officer
Brian K. Bess.................. 140,000 23,500 -- 18,000 --
Vice President -- Engineering
</TABLE>

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

(1) Includes an automobile allowance and club membership dues.

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

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<PAGE> 62

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 merger 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($)(2)
OPTIONS EMPLOYEES IN PRICE EXPIRATION ---------------------------
NAME AND PRINCIPAL POSITION GRANTED(1) FISCAL YEAR ($/SH) DATE 5% 10%
--------------------------- ---------- ------------- -------- ---------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Donald D. Wolf.............................. 187,500 31.9% $ 8.00 4/1/09 $943,750 $2,390,000
Chairman, Chief Executive Officer 120,750 20.5 10.67 9/1/09 809,830 2,052,750
Barth E. Whitham............................ 75,000 12.7 8.00 4/1/09 377,500 956,000
President, Chief Operating Officer,
Secretary 23,100 3.9 10.67 9/1/09 154,924 392,700
Allan D. Keel(3)............................ -- -- -- -- -- --
Vice President -- Gulf of Mexico
Exploration
James H. Shonsey............................ 18,000 3.1 8.00 4/1/09 90,600 229,440
Chief Financial Officer
Brian K. Bess............................... 18,000 3.1 8.00 4/1/09 90,600 229,440
Vice President -- Engineering
</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............................. 750,000 49.8% $10.85 5/8/10 $5,120,000 $12,975,000
Chairman, Chief Executive Officer
Barth E. Whitham........................... 262,500 17.4 10.85 5/8/10 1,792,000 4,541,250
President, Chief Operating Officer,
Secretary
Allan D. Keel(3)........................... -- -- -- -- -- --
Vice President -- Gulf of Mexico
Exploration
James H. Shonsey........................... 38,812 2.6 10.85 5/8/10 264,960 671,456
Chief Financial Officer
Brian K. Bess.............................. 52,710 3.5 10.85 5/8/10 359,833 911,883
Vice President -- Engineering
</TABLE>

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

(1) In 1999, Westport Oil and Gas granted options to purchase a total of 143,850
shares of common stock at an exercise price of $10.67 per share and options
to purchase a total of 444,750 shares of common stock at an exercise price
of $8.00 per share. Such options were terminated in connection with the
merger between Westport Oil and Gas and EPGC.

(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 to employees options to purchase a total of
1,497,925 shares of common stock at an exercise price of $10.89 per share.

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<PAGE> 63

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 750,000 shares and 262,500
shares, respectively, of our common stock at an exercise price of $10.85 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 of 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 all accrued base
salary, business expenses incurred as of such date, 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 October 17, 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
was 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 4,110,813 shares of our common stock for issuance under
the plan. As of October 15, 2000, no options or other awards have been granted
under the plan. However, options to purchase an aggregate of 1,527,441 shares of
our common stock were granted under the EPGC 2000 Stock Option Plan and the EPGC
Directors' Stock Option Plan. Options to purchase an aggregate of 29,516 of
these shares 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

Westport Oil and Gas assumed a retirement savings plan pursuant to the
merger 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. 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> 64

ANNUAL INCENTIVE PLAN

The Westport Annual Incentive Plan 2000 provides an opportunity for
specified 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 allocated to a business
unit will be paid out to each participating employee within such business unit
and 75% of the bonus will be awarded to various individuals within such 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 specified 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 is
eligible to receive royalties from this program.

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<PAGE> 65

CERTAIN TRANSACTIONS

SHAREHOLDERS' AGREEMENT

In connection with the merger 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 extend the provisions in the shareholders'
agreement to the shares of Westport issued to such stockholders. 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 composed 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, 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
the ownership of the party is reduced below designated thresholds;

- 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 is required to approve certain acquisitions and
dispositions;

- following a qualified public offering 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 us or
the managing underwriters in underwritten offerings.

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<PAGE> 66

PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth certain information with respect to the
beneficial ownership of our common stock as of October 15, 2000, and as adjusted
to reflect the sale of the common stock being offered hereby and assuming no
exercise of the underwriters' 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
PRIOR TO THE BENEFICIAL OWNERSHIP
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)................ 33,750 *% -- 33,750 *%
Barth E. Whitham(3).............. 33,750 * -- 33,750 *
James H. Shonsey(4).............. -- -- -- -- --
Kenneth D. Anderson(5)........... -- -- -- -- --
Lynn S. Belcher(6)............... -- -- -- -- --
Brian K. Bess(7)................. -- -- -- -- --
Klein P. Kleinpeter(8)........... -- -- -- -- --
Alex M. Cranberg(9).............. 13,940 * -- 13,940 *
James M. Funk(10)................ 5,422 * -- 5,422 *
Murry S. Gerber.................. -- -- -- -- --
Peter R. Hearl................... 802 * -- 802 *
David L. Porges.................. -- -- -- -- --
Michael Russell.................. -- -- -- -- --
Randy Stein...................... 802 * -- 802 *
William F. Wallace(11)........... 12,920 * -- 12,920 *
Directors and executive officers
as a group(12)................ 101,386 * -- 101,386 *
FIVE PERCENT BENEFICIAL OWNERS AND
SELLING STOCKHOLDERS:
Westport Energy LLC(13).......... 15,563,001 50.4 1,325,000 14,238,001 38.1
21 Glen Oaks Ave.
Summit, NJ 07901
ERI Investments, Inc.(14)........ 15,236,152 49.3 1,325,000 13,911,152 37.2
One Oxford Centre, Suite 3300
Pittsburgh, PA 15219
Richard J. Haas(15).............. 15,563,001 50.4 1,325,000 14,238,001 38.1
Robert A. Haas(15)............... 15,563,001 50.4 1,325,000 14,238,001 38.1
Eugen von Liechtenstein(15)...... 15,563,001 50.4 1,325,000 14,238,001 38.1
Graham Garner(15)................ 15,563,001 50.4 1,325,000 14,238,001 38.1
</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 October 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

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<PAGE> 67

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 is the sole general partner of the Donald D. Wolf Family Limited
Partnership. Mr. Wolf holds options to purchase 750,000 shares of common
stock, none of which is exercisable within 60 days of October 15, 2000.

(3) Mr. Whitham holds options to purchase 262,500 shares of common stock, none
of which is exercisable within 60 days of October 15, 2000.

(4) Mr. Shonsey holds options to purchase 38,812 shares of common stock, none
of which is exercisable within 60 days of October 15, 2000.

(5) Mr. Anderson holds options to purchase 17,394 shares of common stock, none
of which is exercisable within 60 days of October 15, 2000.

(6) Mr. Belcher holds options to purchase 79,831 shares of common stock, none
of which is exercisable within 60 days of October 15, 2000.

(7) Mr. Bess holds options to purchase 52,710 shares of common stock, none of
which is exercisable within 60 days of October 15, 2000.

(8) Mr. Kleinpeter holds options to purchase 45,000 shares of common stock,
none of which is exercisable within 60 days of October 15, 2000.

(9) Mr. Cranberg holds options to purchase 13,018 shares of common stock, all
of which are exercisable within 60 days of October 15, 2000.

(10) Mr. Funk holds options to purchase 4,500 shares of common stock, all of
which are exercisable within 60 days of October 15, 2000.

(11) Mr. Wallace holds options to purchase 11,998 shares of common stock, all of
which are exercisable within 60 days of October 15, 2000.

(12) The directors and executive officers hold options to purchase 1,275,763
shares of common stock, of which, 29,516 options are exercisable within 60
days of October 15, 2000.

(13) All of the interests of Westport Energy LLC are held by Westport
Investments Ltd, a Bahamas corporation. All voting decisions with respect
to the shares of Westport held by Westport Energy LLC are made by the board
of directors of Westport Investments Ltd. No member of the board of
directors of Westport Investments Ltd holds any position with Westport.

(14) ERI Investments, Inc. is an indirect, wholly-owned subsidiary of Equitable
Resources, Inc. Murry S. Gerber, a director of Westport, is chairman,
president and chief executive officer of Equitable Resources, Inc. David L.
Porges, a director of Westport, is executive vice president and chief
financial officer of Equitable Resources, Inc. James A. Funk, a director of
Westport, is president of Equitable Production Company, an indirect,
wholly-owned subsidiary of Equitable Resources, Inc.

(15) Includes 15,563,001 shares of common stock held by Westport Energy LLC. The
board of directors of Westport Investments Ltd consists of Dr. Richard J.
Haas, Robert A. Haas, Eugen von Liechtenstein and Graham Garner, each of
whom disclaims beneficial ownership of the shares of common stock held by
Westport Energy LLC. The address of Dr. Haas and each of Messrs. Haas, von
Liechtenstein and Garner is c/o Westport Resources Corporation, 410
Seventeenth Street, Suite 2300, Denver, Colorado 80202.

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<PAGE> 68

DESCRIPTION OF CAPITAL STOCK

On the closing of this offering, our authorized capital stock will consist
of 70,000,000 shares of common stock, $0.01 par value, and 5,000,000 shares of
preferred stock, $0.01 par value.

COMMON STOCK

As of September 26, 2000, there were 30,884,041 shares of common stock
outstanding that were held of record by ten stockholders. As of June 30, 2000,
there were 1,540,459 shares of common stock subject to outstanding options,
29,516 of which are currently exercisable. There will be 37,384,041 shares of
common stock outstanding (assuming no exercise of the underwriters'
over-allotment option) 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. The
holders of common stock do not have cumulative voting rights. 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. Our credit agreement prohibits us from
declaring or paying any 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 written consent;

- the holders of a majority of our shares issued and outstanding and
entitled to vote, present in person or by proxy, constitute a quorum for
the transaction of business at each shareholder meeting;

- special meetings of the stockholders may only be called by our chairman,
president or secretary; provided, however, that so long as a stockholder
has the power pursuant to the shareholders'
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<PAGE> 69

agreement to nominate at least two directors, any director nominated by
such stockholder may also call a special meeting of the stockholder;

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

- 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 then 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.

REGISTRATION RIGHTS

After this offering, the holders of approximately 28,149,153 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 a public offering of 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. 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.

All holders with registration rights have agreed not to exercise their
rights until 180 days following the date of this prospectus without the consent
of Credit Suisse First Boston Corporation.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common stock is Computershare
Trust Company, Inc.

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<PAGE> 70

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 by our existing stockholders
of a substantial number of shares of our common stock held by them 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 37,384,041
shares of common stock, assuming the underwriters' over-allotment option is not
exercised. Of these shares, 9,150,000 shares, or 10,500,000 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 28,234,041 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 of ours, 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 373,840 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 of ours, 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 our 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 4,110,813 shares issuable on exercise
of the options, of which options to purchase 1,527,441 shares 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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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.

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
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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.

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

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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 Internal Revenue Service.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting
agreement, dated October 19, 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...................... 2,642,560
Donaldson, Lufkin & Jenrette Securities Corporation......... 1,403,860
Lehman Brothers Inc. ....................................... 1,403,860
Banc of America Securities LLC.............................. 1,403,860
Petrie Parkman & Co., Inc. ................................. 1,403,860
A.G. Edwards & Sons, Inc. .................................. 223,000
Howard Weil A division of Legg Mason Wood Walker, Inc....... 223,000
J.P. Morgan Securities Inc. ................................ 223,000
PaineWebber Incorporated.................................... 223,000
---------
Total............................................. 9,150,000
=========
</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 may be terminated.

We have granted to the underwriters a 30-day option to purchase on a pro
rata basis up to 1,350,000 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 selling concession of $0.6075 per
share. The underwriters and the selling group members may allow a discount of
$0.10 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........................... $1.0125 $1.0125 $6,581,250 $7,948,125
Expenses payable by us................. $ 0.18 $ 0.15 $1,157,798 $1,157,798
Underwriting Discounts and Commissions
paid by the selling stockholders..... $1.0125 $1.0125 $2,683,125 $2,683,125
</TABLE>

The underwriters do not intend to confirm sales to any accounts over which
they exercise discretionary authority.

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 our credit agreement.
Accordingly, the offering is being made in compliance with the requirements of
Rule 2710(c)(8) of the National

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Association of Securities Dealers, Inc. Conduct Rules. This rule provides
generally that if more than 10% 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
Corporation 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 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, employee stock
purchases pursuant to the terms of a plan in effect on the date of this
prospectus and the filing of registration statements on Form S-8 with the
Securities and Exchange Commission registering securities issuable under any
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 of these
transactions are to be settled by delivery of our common stock or other
securities, in cash or otherwise, or publicly disclose the intention to make any
offer, sale, pledge or disposition, or to enter into any of these types of
transactions, 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. Credit Suisse First Boston Corporation
has no current intention to release any shares subject to lock-up. In
considering whether to release any shares, Credit Suisse First Boston
Corporation would consider, among other factors, the particular circumstances
surrounding the request, including, but not limited to, the number of shares to
be released, the possible impact on the market for our common stock, the reasons
for the request, and whether the holder of our shares requesting the release is
an officer, director or other affiliate of ours.

The underwriters have reserved for sale, at the initial public offering
price, up to 103,960 shares of the common stock for employees, directors and
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 these persons
purchase the 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.

The shares of common stock have been approved for listing on The New York
Stock Exchange under the symbol "WRC."

In connection with the merger 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.

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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. The principal factors in
determining the initial public offering price include:

- 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 that 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.

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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.

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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 made. Any resale
of the common stock in Canada may be made under applicable securities laws which
will vary depending on the relevant jurisdiction, and which may require resales
to be made under available statutory exemptions or under 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

By purchasing common stock in Canada and accepting a purchase confirmation,
a purchaser is representing to us, the selling stockholders and the dealer from
whom such purchase confirmation is received that:

- the purchaser is entitled under applicable provincial securities laws to
purchase our common stock without the benefit of a prospectus qualified
under those securities laws,

- where required by law, the purchaser is purchasing as principal and not
as agent, and

- the 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 the purchaser pursuant to this offering. The 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 report must be filed
for 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 about the eligibility of the common stock for
investment by the purchaser under relevant Canadian legislation.

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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 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 statements 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.

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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.

Bcf. One billon cubic feet of natural gas at standard atmospheric
conditions.

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.

EXPLOITATION. The continuing development of a known producing formation in
a previously discovered field. To make complete or maximize the ultimate
recovery of oil or natural gas from the field by work including development
wells, secondary recovery equipment, or other suitable processes and technology.

EXPLORATION. The search for natural accumulations of oil and natural gas by
any geological, geophysical or other suitable means.

EXPLORATORY WELL. A well drilled either in search of a new and as yet
undiscovered accumulation of oil or natural gas, or with the intent to greatly
extend the limits of a pool already partly developed.

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.

FRACTURE STIMULATION TECHNOLOGY. The technique of improving a well's
production or injection rates by pumping a mixture of fluids into the formation
and rupturing the rock, creating an artificial channel. As part of this
technique, sand or other material may also be injected into the formation to
keep the channel open, so that fluids or gases may more easily flow through the
formation.

GROSS ACRES. The total acres in which we have a working interest.

GROSS PRODUCING WELLS. The total number of producing wells in which we own
any amount of 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.

INJECTION WELL OR INJECTION. 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.

78
<PAGE> 81

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.

MINERAL INTEREST. The property interest that includes the right to enter to
explore for, drill for, produce, store and remove oil and natural gas from the
subject lands, or to lease to another for those purposes.

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, measured at standard
atmospheric conditions.

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.

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. Gross acres multiplied by the percentage working interest owned
by us.

NET PRESENT VALUE. The present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance with
SEC guidelines, net of estimated lease operating expense, production taxes 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, or Federal income taxes and discounted
using an annual discount rate of 10%.

NET PRODUCING WELLS. The sum of all the complete and partial well ownership
interests (i.e., if we own 25% percent of the working interest in eight
producing wells, the subtotal of this interest to the total net producing well
count would be two net producing wells).

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.

NON-OPERATED WORKING INTEREST. The working interest or fraction thereof in
a lease or unit, the owner of which is without operating rights by reason of an
operating agreement.

NYMEX. New York Mercantile Exchange.

OIL AND GAS LEASE. An instrument which grants to another (the lessee) the
exclusive right to enter to explore for, drill for, produce, store and remove
oil and natural gas on the mineral interest, in consideration for which the
lessor is entitled to certain rents and royalties payable under the terms of the
lease. Typically, the duration of the lessee's authorization is for a stated
term of years and "for so long thereafter" as minerals are producing.

OPERATED WORKING INTERESTS. Where the working interests for a property are
co-owned, and where more than one party elects to participate in the development
of a lease or unit, there is an operator designated "for full control of all
operations . . . within the limits of the operating agreement" for the
development and production of the wells on the co-owned interests. The working
interests of the operating party become the "operated working interests."

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

79
<PAGE> 82

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

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.

SECONDARY RECOVERY. An artificial method or process used to restore or
increase production from a reservoir after the primary production by the natural
producing mechanism and reservoir pressure has experienced partial depletion.
Gas injection and waterflooding are examples of this technique.

SEISMIC LICENSES. Term licenses granted by owners of seismic data for
financial consideration providing the licensee with nonexclusive access to
seismic records pertaining to specific geographic areas.

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, measured at standard
atmospheric conditions.

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

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.

80
<PAGE> 83

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
WESTPORT:
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 Sheets as of December 31, 1999 and
June 30, 2000.......................................... F-20
Consolidated Statements of Operations for the six months
ended June 30, 1999 and 2000........................... F-21
Consolidated Statements of Cash Flows for the six months
ended June 30, 1999 and 2000........................... F-22
Notes to Consolidated Financial Statements................ F-23
EPGC PROPERTIES:
Report of Independent Public Accountants.................. F-26
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-27
Notes to Statements of Revenues and Direct Operating
Expenses for the EPGC Properties....................... F-28
</TABLE>

F-1
<PAGE> 84

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 (except with
respect to the matter discussed in
Note 12, as to which the date is
October 17, 2000).

F-2
<PAGE> 85

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, $0.01 par value; and 70,000,000 shares
authorized; 15,630,501 and 13,580,501 shares issued and
outstanding at December 31, 1999 and 1998,
respectively........................................... 136 156
Additional paid-in capital................................ 181,915 198,295
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> 86

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......................................... 9,326 11,004 14,727
======== ======== =======
Net loss per common share:
Basic and Diluted......................................... $ (1.01) $ (4.49) $ (0.21)
======== ======== =======
</TABLE>

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

F-4
<PAGE> 87

WESTPORT OIL AND GAS COMPANY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
RETAINED
COMMON STOCK ADDITIONAL EARNINGS
--------------- PAID-IN (ACCUMULATED
SHARES AMOUNT CAPITAL DEFICIT) TOTAL
------ ------ ---------- ------------ --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996.............. 5,836 $ 58 $ 76,985 $ 3,428 $ 80,471
Purchase of common stock by Parent (Note
5)................................... 3,802 38 59,970 -- 60,008
Net loss................................ -- -- -- (9,381) (9,381)
------ ---- -------- -------- --------
Balance at December 31, 1997.............. 9,638 96 136,955 (5,953) 131,098
Purchase of common stock by Parent (Note
5)................................... 3,943 40 44,960 -- 45,000
Net Loss................................ -- -- -- (49,361) (49,361)
------ ---- -------- -------- --------
Balance at December 31, 1998.............. 13,581 136 181,915 (55,314) 126,737
Purchase of common stock by Parent (Note
5)................................... 2,050 20 16,380 -- 16,400
Net loss................................ -- -- -- (3,126) (3,126)
------ ---- -------- -------- --------
Balance at December 31, 1999.............. 15,631 $156 $198,295 $(58,440) $140,011
====== ==== ======== ======== ========
</TABLE>

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

F-5
<PAGE> 88

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
Exploratory dry hole costs............................. 1,706 9,487 2,032
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................... 24,146 7,622 21,279
--------- -------- -------
Cash flows from investing activities:
Additions to property and equipment....................... (46,783) (49,630) (14,005)
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......... (150,441) (113,019) 17,981
--------- -------- -------
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> 89

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 by Westport
Energy LLC ("Parent") as a Delaware corporation on July 5, 1991. As of December
31, 1999, the Company was a 99.6% owned subsidiary of the 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.

Revenue Recognition

The Company follows the sales method of accounting for oil and natural gas
revenues. Under this method, revenues are recognized based on actual volumes of
oil and natural gas sold to purchasers.

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. The $5.8 million impairment recorded in 1997 was the
result of depressed oil prices at year-end related to long-lived oil assets
located in the Rocky Mountains. Impairments recorded in 1998, were the result of
depressed oil and natural gas prices at year-end, including $4.9 million for
long-lived oil properties located primarily in the Rocky Mountains and $2.5
million for natural gas properties located in the Mid-Continent, and $1.4
million based on the results of unsuccessful development drilling in the
Mid-Continent. The impairment recorded in 1999 was the result of a decrease in
risk adjusted probable reserves for the Ward Estes lease located in West Texas,
which were subsequently assigned to the operator of the lease in exchange for
existing producing property equipment and infrastructure owned by the operator.

F-7
<PAGE> 90
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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.

Consolidated Statements of Cash Flows

For purposes of the Statements of Cash Flows, the costs of exploratory dry
holes are included in cash flows from investing activities.

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

F-8
<PAGE> 91
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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.

F-9
<PAGE> 92
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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.

Comprehensive Income

The Company follows the provisions of SFAS No. 130, "Reporting
Comprehensive Income." SFAS No. 130 establishes standards for reporting and
display of comprehensive income and its components in a full set of
general-purpose financial statements. In addition to net income, comprehensive
income includes all changes in equity during a period, except those resulting
from investments and distributions to owner. The Company had no such changes in
1999, 1998 or 1997.

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.

F-10
<PAGE> 93
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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>

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.

F-11
<PAGE> 94
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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.

F-12
<PAGE> 95
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 3,802,281, 3,942,758, and 2,050,001 common shares
were purchased by the Parent for per share prices of $15.78, $11.41, and $8.00,
respectively. The share prices reflected the estimated market value of the
Company's stock at the time of purchase. The estimated market value is
determined utilizing a valuation model that is based on the pre tax discounted
future net revenues from the Company's oil and gas reserves adjusted for the
Company's other assets and liabilities.

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 652,500 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, 400,973, 84,750 and 588,600,
respectively, shares of the Company's common stock were granted under the Stock
Option Plan at exercise prices between $8.00 and $15.78 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 40,500 shares of common stock
for issuance under the Directors' Stock Option Plan. During 1997, 1998 and 1999,
9,000 shares, of the Company's common stock were granted under the Directors'
Stock Option Plan at exercise prices of between $8.00 and $15.78 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 333,563 shares
of the Company's common stock and reduced the exercise price of options to
purchase 746,910 shares of the Company's common stock from $15.37 per share to
$8.00 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 453,750 shares of the Company's common stock at an exercise price of
$8.00 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 746,910 repriced options discussed above (plus 333,563 of the
additional options granted on April 1, 1999 and deemed to have replaced the
cancelled options) as variable awards through the date of

F-13
<PAGE> 96
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.......................... 573,750 3,000 $15.78
Options granted..................................... 400,973 9,000 15.68
--------- ------
Balance at December 31, 1997.......................... 974,723 12,000 15.74
Options granted..................................... 84,750 9,000 11.41
--------- ------
Balance at December 31, 1998.......................... 1,059,473 21,000 15.37
Options cancelled................................... (328,098) (5,465) 15.37
Options granted..................................... 588,600 9,000 8.64
--------- ------
Balance at December 31, 1999.......................... 1,319,975 24,535 8.29
========= ======
Options exercisable at December 31, 1997.............. 139,500 12,000 15.74
========= ======
Options exercisable at December 31, 1998.............. 376,619 21,000 15.65
========= ======
Options exercisable at December 31, 1999.............. 431,009 24,535 8.00
========= ======
</TABLE>

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.......................................... $ (1.01) $ (4.49) $ (0.21)
Pro forma............................................ (1.07) (4.58) (0.28)
</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 $3.89, $2.69 and $4.21, 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.

F-14
<PAGE> 97
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

9. PRODUCING PROPERTIES ACQUISITIONS AND DIVESTITURES:

Total Minatome Corporation Property 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, subsequent to the TMC Acquisition the Purchaser assigned the Company
a 31% interest in the individual assets and liabilities of TMC ("TMC Property
Acquisition"), which consist primarily of working interests in oil and natural
gas properties, for consideration of approximately $56 million. The TMC Property
Acquisition was funded by sales of common stock to the Company's Parent and
borrowings under the Credit Agreement. The TMC Property 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
Property Acquisition for the 3-month period ended December 31, 1998 was
approximately $5.5 million.

F-15
<PAGE> 98
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other Acquisitions

During 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 EVENT -- ACQUISITION:

The Company is currently in negotiations with Equitable Resources, Inc.
("Equitable") for the acquisition of an oil and natural gas subsidiary (EPGC) of
Equitable. EPGC's assets consist of oil and natural gas properties 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 merger using
purchase accounting. The Company anticipates closing the acquisition during
early 2000.

12. SUBSEQUENT EVENT -- INITIAL PUBLIC OFFERING:

On June 29, 2000, Westport Resources Corporation filed a registration
statement on Form S-1 with the Securities and Exchange Commission for an initial
public offering ("IPO") of the Company's common stock.

Prior to completion of the IPO, the Board of Directors approved a restated
Westport Resources Corporation certificate of incorporation in Delaware.
Subsequent to filing of the restated certificate, the Company split the common
stock on a three-for-two basis (the "Stock Split") by way of a stock dividend.
All par value, authorized shares, common share and common per share amounts have
been retroactively restated in the accompanying consolidated financial
statements to reflect the Stock Split.

F-16
<PAGE> 99
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. 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..................................... 11,298 19,806 7,958
Development costs..................................... 19,991 15,164 3,695
-------- -------- -------
Total......................................... $147,784 $112,781 $13,989
======== ======== =======
</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-17
<PAGE> 100
WESTPORT OIL AND GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

future income taxes based on statutory income tax rates in effect at each
year end, 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(Mbls) GAS(Mmcf)
--------- ---------
<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-18
<PAGE> 101
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-19
<PAGE> 102

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
1999 2000
-------------- -------------
(UNAUDITED)
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS

Current Assets:
Cash and cash equivalents................................. $ 19,475 $ 15,684
Accounts receivable -- net................................ 14,645 40,800
Prepaid expenses.......................................... 1,712 1,951
-------- ----------
Total current assets.............................. 35,832 58,435
-------- ----------
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method:
Proved properties...................................... 307,068 520,972
Unproved properties.................................... 18,089 46,267
Office furniture and equipment............................ 2,182 2,324
Leasehold improvements.................................... 488 496
-------- ----------
327,827 570,059
Less accumulated depletion, depreciation and amortization... (92,950) (115,474)
-------- ----------
Net property and equipment........................ 234,877 454,585
-------- ----------
Other assets................................................ 768 1,047
-------- ----------
Total assets...................................... $271,477 $ 514,067
======== ==========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable.......................................... $ 8,482 $ 11,416
Accrued expenses.......................................... 10,574 6,171
Ad valorem taxes payable.................................. 2,606 3,622
Current portion of long-term debt......................... 1,333 667
-------- ----------
Total current liabilities......................... 22,995 21,876
-------- ----------
Long-term debt.............................................. 105,462 155,462
Deferred income taxes....................................... -- 16,153
Other liabilities........................................... 3,009 1,678
-------- ----------
Total liabilities................................. 131,466 195,169
-------- ----------
Stockholders' equity:
Common stock, $0.01 par value; 70,000,000 authorized;
15,630,501 and 30,869,419 shares issued and outstanding
at December 31, 1999 and June 30, 2000, respectively... 156 309
Additional paid-in capital................................ 198,295 366,423
Accumulated retained deficit.............................. (58,440) (47,834)
-------- ----------
Total stockholders' equity........................ 140,011 318,898
-------- ----------
Total liabilities and stockholders' equity........ $271,477 $ 514,067
======== ==========
</TABLE>

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

F-20
<PAGE> 103

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE THREE MONTHS FOR THE SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
--------------------- -------------------
1999 2000 1999 2000
--------- --------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Operating revenues:
Oil and natural gas sales............................ $16,913 $52,563 $31,891 $77,548
Operating costs and expenses:
Lease operating expense.............................. 4,519 8,857 10,139 15,480
Production taxes..................................... 1,388 2,376... 2,186 4,644
Exploration.......................................... 1,053 4,392 2,091 6,263
Depletion, depreciation and amortization............. 7,820 16,404 16,309 22,576
Impairment of unproved properties.................... 3 1,306 3 1,541
General and administrative........................... 1,415 2,040 2,995 6,587
------- ------- ------- -------
Total operating expenses..................... 16,198 35,375 33,723 57,091
------- ------- ------- -------
Operating income (loss)...................... 715 17,188 (1,832) 20,457
------- ------- ------- -------
Other income (expense):
Interest expense..................................... (2,080) (3,240) (4,577) (5,288)
Interest income...................................... 115 182 215 375
Gain (loss) on sale of assets -- net................. (373) 6 4,397 (11)
Other................................................ 6 32 20 32
------- ------- ------- -------
(2,332) (3,020) 55 (4,892)
------- ------- ------- -------
Income (loss) before income taxes...................... (1,617) 14,168 (1,777) 15,565
Benefit (provision) for income taxes................... -- (4,959) -- (4,959)
------- ------- ------- -------
Net income (loss)...................................... $(1,617) $ 9,209 $(1,777) $10,606
======= ======= ======= =======
Weighted average number of common shares outstanding:
Basic................................................ 14,031 22,785 13,806 22,785
======= ======= ======= =======
Diluted.............................................. 14,031 22,969 13,806 22,975
======= ======= ======= =======
Net income (loss) per common share:
Basic................................................ $ (0.12) $ 0.40 $ (0.13) $ 0.47
======= ======= ======= =======
Diluted.............................................. $ (0.12) $ 0.40 $ (0.13) $ 0.46
======= ======= ======= =======
</TABLE>

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

F-21
<PAGE> 104

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE SIX MONTHS
ENDED JUNE 30,
-------------------
1999 2000
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Cash flows from operating activities
Net income (loss)......................................... $ (1,777) 10,606
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depletion, depreciation and amortization............... 16,309 22,576
Exploratory dry hole costs............................. 230 1,739
Impairment of unproved properties...................... 3 1,541
Deferred income taxes.................................. -- 4,959
Loss (gain) on sale of assets.......................... (4,397) 11
Director retainers settled for stock................... -- 30
Changes in assets and liabilities:
Increase in accounts receivable...................... (2,303) (18,458)
Increase in prepaid expenses......................... (324) (239)
Increase (decrease) in accounts payable.............. (3,783) 799
Increase (decrease) in ad valorem taxes payable...... (92) 1,016
Decrease in accrued expenses......................... (3,279) (4,402)
Decrease in other liabilities........................ (136) (1,331)
-------- --------
Net cash provided by operating activities................... 451 18,847
-------- --------
Cash flows from investing activities:
Additions to property and equipment....................... (2,200) (27,892)
Proceeds from sale of assets.............................. 24,275 57
Merger with EPGC.......................................... -- (42,403)
Other acquisitions........................................ 449 (1,454)
Other assets.............................................. 24 (279)
-------- --------
Net cash provided by (used in) investing activities......... 22,548 (71,971)
-------- --------
Cash flows from financing activities:
Purchase of common stock by parent........................ 16,400 --
Proceeds from long-term debt.............................. -- 50,000
Repayment of long-term debt............................... (39,167) (667)
-------- --------
Net cash used in financing activities....................... (22,767) 49,333
-------- --------
Net increase (decrease) in cash and cash equivalents........ 232 (3,791)
Cash and cash equivalents at beginning of period............ 10,148 19,475
-------- --------
Cash and cash equivalents at end of period.................. $ 10,380 $ 15,684
======== ========
Supplemental cash flow information:
Cash paid for interest.................................... $ 5,330 $ 3,753
======== ========
Cash paid for income taxes................................ $ -- $ --
======== ========
Supplemental schedule of noncash investing and financing
activities:
Common stock issued in connection with the EPGC merger.... $ -- $165,363
======== ========
Liabilities assumed in connection with the EPGC merger.... $ -- $ 1,850
======== ========
EPGC merger expenses paid by parent....................... $ -- $ 2,895
======== ========
</TABLE>

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

F-22
<PAGE> 105

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. ORGANIZATION AND NATURE OF BUSINESS

On April 7, 2000, Westport Oil and Gas Company, Inc. merged with Equitable
Production (Gulf) Company ("EPGC"), an indirect subsidiary of Equitable
Resources, Inc. that held certain Gulf of Mexico assets of its parent company,
Equitable Production Company (the "EPGC Properties"). This transaction was
effected by a merger between a newly-formed subsidiary of EPGC and Westport Oil
and Gas Company, Inc., resulting in Westport Oil and Gas Company, Inc. becoming
a wholly-owned subsidiary of EPGC, which subsequently changed its name to
Westport Resources Corporation (the "Company"). The Company is owned 50.4% by
Westport Energy LLC and 49.4% by ERI Investments, Inc. The remaining 0.2% is
owned by two executive officers and three directors 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 June 30, 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 1,344,510 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 six months ended June 30, 2000. The cost to
repurchase the stock options was based on the difference between $10.85 and the
exercise prices of $8.00 and $10.67 of such options. See Note 5.

4. MERGER

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 from bank borrowings, issued 15.236 million shares of common stock
valued at $10.85 per share and assumed liabilities of $1.85 million to
consummate the merger.

F-23
<PAGE> 106
WESTPORT RESOURCES CORPORATION

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

The total purchase price of $217.2 million was allocated as follows (in
thousands):

<TABLE>
<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........................................... $217,206
========
</TABLE>

The value of the shares was determined utilizing a valuation model to determine
a Net Asset Value ("NAV") for each company based on the pre-tax discounted
future net revenues of the companies' oil and gas reserves, derived from third
party engineering reports, adjusted for the companies' other assets and
liabilities. The EPGC properties consist of 37 producing properties and 30
undeveloped blocks in the Gulf of Mexico. The results of operations of EPGC are
included in the income statement of Westport Resources Corporation for the
period from April 7, 2000 through June 30, 2000.

PRO FORMA RESULTS OF OPERATIONS

The following table reflects the pro forma results of operations for the
six-month period ended June 30, 2000 and 1999 as though the merger had occurred
as of January 1, 1999. The pro forma amounts are not necessarily indicative of
the results that may be reported in the future.

<TABLE>
<CAPTION>
2000 1999
--------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
<S> <C> <C>
Revenues.................................................... $96,480 $58,015
Net income (loss)........................................... 13,930 (761)
Basic net income (loss) per share........................... 0.45 (0.03)
Diluted net income (loss) per share......................... 0.45 (0.03)
</TABLE>

5. STOCK OPTION GRANTS

The Company granted options to purchase 1,548,163 shares of common stock on
May 8, 2000 to certain employees and directors at an exercise price of $10.85
per share. The options vest ratably over three years from the date of grant and
have a term of 10 years. Of the 1,548,163 options granted, 1,344,510 options are
deemed to be replacement options (the "Replacement Options") for those options
repurchased by the Company on March 24, 2000. See Note 3.

F-24
<PAGE> 107
WESTPORT RESOURCES CORPORATION

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

will be recognized on a prospective basis from July 1, 2000. Under provisions of
the Interpretation, we will be required to account for 1,080,473 of the
Replacement 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.

The 467,690 options not considered to be variable options will not be
subject to variable award accounting.

6. COMMITMENTS AND CONTINGENCIES

The Company entered into employment agreements on May 8, 2000 with its
chief executive officer and president, which provide for annual base salaries of
$325,000 and $225,000, respectively, subject to annual adjustments through May
31, 2003. The agreements provide for severance payments equal to three times the
individual's then applicable base salary and three times the average of the
bonus the individual received the last three years if the Company terminates
such person's employment other than for cause or if such person's employment is
terminated upon a change of control of Westport.

F-25
<PAGE> 108

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-26
<PAGE> 109

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-27
<PAGE> 110

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. ("Equitable") formed to hold
interests in Equitable's Gulf of Mexico oil and natural gas properties,
including 37 producing properties and 30 undeveloped blocks (the "EPGC
Properties"). 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 and
reflect the revenues and direct operating expenses of EPGC's 37 producing
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......................... (332) (10,628) (614) (18,782) (761) (23,100)
Revisions of previous estimates.... 133 3,049 282 (4,195) (652) 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 4,686 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-28
<PAGE> 111
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
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash flows.................................... $270,768 $215,350 $361,475
Future production costs.............................. (52,121) (75,702) (48,296)
Future development costs............................. (37,151) (28,525) (58,025)
-------- -------- --------
Future net cash flows before tax..................... 181,496 111,123 255,154
Future income taxes.................................. (33,051) -- (52,578)
-------- -------- --------
Future net cash flows after tax...................... 148,445 111,123 202,576
Annual discount at 10%............................... (28,867) (19,041) (38,916)
-------- -------- --------
Standardized measure of discounted future net cash
flows.............................................. $119,578 $ 92,082 $163,660
======== ======== ========
</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
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of year.................................... $ 36,380 $119,577 $ 92,082
Oil and natural gas sales, net of production
costs........................................... (27,954) (35,525) (55,844)
Net changes in anticipated prices and production
costs........................................... (18,542) (84,392) 48,741
Extensions and discoveries, less related costs..... 36,540 45,423 83,188
Changes in estimated future development costs...... 170 16,783 14,000
Revision of quantity estimates..................... 4,820 (2,385) 7,129
Purchases of minerals in place..................... 97,017 -- --
Sales of minerals in place......................... -- -- 2,096
Accretion of discount.............................. 3,638 11,958 9,208
Net change in income taxes......................... (13,798) 17,508 (31,624)
Changes in production rates and other.............. 1,307 3,135 (5,316)
-------- -------- --------
End of year.......................................... $119,578 $ 92,082 $163,660
======== ======== ========
</TABLE>

F-29
<PAGE> 112

[NSAI TOP LETTERHEAD]

August 22, 2000

Mr. Barth E. Whitham
Westport Resources Corporation
410 Seventeenth Street, Suite 2300
Denver, Colorado 80202-4436

Dear Mr. Whitham:

In accordance with your request, we have estimated the proved reserves and
future revenue, as of July 1, 2000, to the Westport Resources Corporation
(Westport) interest in certain oil and gas properties located in federal waters
offshore Louisiana and Texas and in the State of Oklahoma as listed in the
accompanying tabulations. This report has been prepared using constant prices
and costs and conforms to the guidelines of the Securities and Exchange
Commission (SEC).

As presented in the accompanying Tables I through IV, we estimate the
proved net reserves and future net revenue to the Westport interest, as of July
1, 2000, to be:

<TABLE>
<CAPTION>
Net Reserves Future Net Revenue (M$)
---------------------------- -------------------------
Oil NGL Gas Present Worth
Category (Mbbl) (Mbbl) (Mmcf) Total at 10%
-------------------------------- ------- ------ --------- --------- -------------
<S> <C> <C> <C> <C> <C>
Proved Developed
Producing 465.9 39.4 43,185.0 154,787.6 140,438.3
Non-Producing 1,155.4 133.7 39,292.4 176,289.6 123,879.9
Proved Undeveloped 1,607.9 125.0 18,935.4 110,971.8 72,594.4
------- ----- --------- --------- ---------
Total Proved 3,229.2 298.1 101,412.8 442,049.0 336,912.6
</TABLE>

The oil reserves shown include crude oil and condensate. Oil and gas plant
liquid (NGL) 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 revenue shown in this report are for
proved developed producing, proved developed non-producing and proved
undeveloped reserves. 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. As requested, value for probable and
possible reserves which exist for these properties has not been included.

Future gross revenue to the Westport 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; future net revenue for the offshore
properties is also after

[NSAI BOTTOM LETTERHEAD]

A-1
<PAGE> 113

[NSAI SHORT TOP LETTERHEAD]

deducting abandonment costs. The future net revenue has been discounted at an
annual rate of 10 percent to determine its "present worth." The present worth is
shown to indicate the effect of time on the value of money and should not be
construed as being the fair market value of the properties.

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

Oil prices used in this report are based on the June 30, 2000 NYMEX West
Texas Intermediate spot price of $32.50 per barrel, adjusted by lease for
gravity, transportation fees, and regional posted price differentials. The NGL
price used is $24.38 per barrel. Gas prices used in this report are based on the
June 30, 2000 NYMEX Henry Hub spot market price of $4.33 per MMBTU, adjusted by
lease for energy content, transportation fees, and regional price differentials.
Oil, NGL, and gas prices are held constant in accordance with SEC guidelines.

Lease and well operating costs are based on operating expense records of
Westport. 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. Headquarters general and administrative overhead expenses of
Westport are not included. Lease and well operating costs are held constant in
accordance with SEC guidelines. Capital costs are included as required for
workovers, new development wells, and production equipment.

We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the Westport
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 Westport 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.

A-2
<PAGE> 114

[NSAI SHORT TOP LETTERHEAD]

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
Westport Resources Corporation, other interest owners, various operators of the
properties, and the nonconfidential files of Netherland, Sewell & Associates,
Inc. and were accepted as accurate. We are independent petroleum engineers,
geologists, and geophysicists; we do not own an interest in these properties and
are not employed on a contingent basis. Basic geologic and field performance
data together with our engineering work sheets are maintained on file in our
office.

Very truly yours,

/s/ FREDERIC D. SAMUEL

CHR:TWB

A-3
<PAGE> 115

[RYDER SCOTT TOP LETTERHEAD]

AUGUST 14, 2000

Westport Resources Corporation
410 Seventeenth Street, Suite 2410
Denver, Colorado 80200

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 Resources Corporation as of June 30, 2000. The subject properties
are located in the states of Colorado, Kansas, Louisiana, Michigan, New Mexico,
North 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) requirements for future price and
cost parameters.

The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. Hydrocarbon prices in effect at June 30, 2000
were used in the preparation of this report as required by SEC rules; however,
actual future prices may vary significantly from June 30, 2000 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
received may differ significantly from the estimated quantities presented in
this report. The results of this study are summarized below.

SEC PARAMETERS

ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
WESTPORT RESOURCES CORPORATION
AS OF JUNE 30, 2000

<TABLE>
<CAPTION>
PROVED
--------------------------------------------------------------
DEVELOPED
------------------------------
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL PROVED
-------------- ------------- ------------ --------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate -- Barrels 25,856,370 4,200,459 4,733,915 34,790,740
Plant Products -- Barrels 31,305 0 0 31,305
Gas -- MMCF 77,242 14,714 35,670 127,626
INCOME DATA*
Future Gross Revenue $1,015,424,000 $174,927,300 $272,868,000 $1,463,220,000
Deductions 328,619,000 35,165,200 71,690,860 435,475,000
-------------- ------------ ------------ --------------
Future Net Income (FNI) $ 686,879,900 $139,762,200 $201,177,100 $1,027,819,000
Discounted FNI @ 10% $ 428,094,300 $ 76,916,640 $116,363,700 $ 621,374,700
</TABLE>

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

* From Landmark Graphics' "ARIES"

[RYDER SCOTT BOTTOM LETTERHEAD]
A-4
<PAGE> 116
Westport Resources Corporation
August 14, 2000
Page 2

At Westport Resources Corporation's request, all economic evaluations were
made using Landmark Graphics' "ARIES". Due to rounding calculations, total value
may not add up exactly.

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.

The future gross revenue is after the deduction of production taxes. The
deductions comprise the normal direct costs of operating the wells, ad valorem
taxes, recompletion costs and development costs. The future net income includes
the value of the net profit interest in the Bonanza Field. This results in a
higher value than would be calculated by subtracting the deductions from the
future gross revenue. 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.
Liquid hydrocarbon reserves account for approximately 67.7 percent, gas reserves
account for approximately 32.0 percent and other income from carbon dioxide and
income from various overriding royalty interests account for the remaining 0.3
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 below.

<TABLE>
<CAPTION>
Discounted Future Net Income
As of June 30, 2000
-------------------------------------------
Discount Rate Total
Percent Proved
------------------------------- ------
<S> <C>
8 $672,431,400
12 $578,243,500
15 $524,733,700
20 $456,455,000
</TABLE>

The results shown above are presented for your information and should not
be construed as our estimate of fair market value.

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 definitions
of proved reserves are included under the tab "Reserve Definitions" in this
report.

Because of the direct relationship between volumes of proved undeveloped
reserves and development plans, we include in the proved undeveloped category
only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled, and reserves assigned to the undeveloped portions of
secondary or tertiary projects which we have been assured will definitely be
developed.

The various reserve status categories are defined under the tab "Reserve
Definitions" in this report.

A-5
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Westport Resources Corporation
August 14, 2000
Page 3

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. 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
that are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment 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 Resources Corporation.

HYDROCARBON PRICES

Westport Resources Corporation furnished us with hydrocarbon prices in
effect at June 30, 2000 and with its forecasts of future prices which take into
account SEC and Financial Accounting Standards Board (FASB) rules, current
market prices, contract prices, and fixed and determinable price escalations
where applicable.

In accordance with FASB Statement No. 69, June 30, 2000 market prices were
determined using the daily oil price or daily gas sales price ("spot price")
adjusted for oilfield or gas gathering hub and wellhead price differences (e.g.
grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in
accordance with SEC and FASB specifications, changes in market prices subsequent
to June 30,2000 were not considered in this report.

For hydrocarbon products sold under contract, the contract price including
fixed and determinable escalations, exclusive of inflation adjustments, was used
until expiration of the contract. Upon contract expiration, the price was
adjusted to the current market price for the area and held at this adjusted
price to depletion of the reserves.

The effects of derivative instruments designated as price hedges of oil and
gas quantities are generally not reflected in our individual property
evaluations.

A-6
<PAGE> 118
Westport Resources Corporation
August 14, 2000
Page 4

COSTS

Operating costs for the leases and wells in this report are based on the
operating expense reports of Westport Resources Corporation 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. 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.

Development costs were furnished to us by Westport Resources Corporation
and are based on authorizations for expenditure for the proposed work or actual
costs for similar projects. The estimated net cost of abandonment after salvage
was included for properties where abandonment costs net of salvage are
significant. The estimates of the net abandonment costs furnished by Westport
Resources Corporation were accepted without independent verification. At the
request of Westport Resources Corporation, their estimate of zero abandonment
costs after salvage value for 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 Resources Corporation's
estimates.

Current costs were held constant throughout the life of the properties.

GENERAL

Ryder Scott Company performed the reserve analysis and made the projection
of future production; however, at the request of Westport Resources Corporation,
the economic analyses were performed on Landmark Graphics' "ARIES". Ryder Scott
Company has confirmed that the values used for scheduling production and
calculating production and ad valorem taxes were correct. In addition, Ryder
Scott Company has accepted the ownership interest and prices supplied by
Westport Resources Corporation as correct and has not attempted to verify those
values. The tables presented in this report are generated by ARIES and are
located behind the "Appendix" tab.

A one line summary of gross and net reserves and income data for each of
the subject properties is located behind the tab titled "one line summary of
gross and net reserves and income data". Our estimated projection of production
and income by years beginning June 30, 2000 by reserve category are located
behind the Grand Summary tab. These tables are all included in the "Summary
Report". Our estimated projection of production and income by years beginning
June 30, 2000 by state, field, and lease or well are located behind the tab
titles "Lease Tables" These tables are presented in the "Detail Report" (3
volumes).

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 Resources Corporation 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
that may exist nor were any costs included for potential liability to restore
and clean up damages, if any, caused by past operating practices. Westport
Resources Corporation 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 Resources Corporation were accepted without
independent verification.

A-7
<PAGE> 119
Westport Resources Corporation
August 14, 2000
Page 5

Westport Resources Corporation has assured us of their intent and ability
to proceed with the development activities included in this report, and that
they are not aware of any legal, regulatory or political obstacles that would
significantly alter their plans.

Neither Ryder Scott Company 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 and sole benefit of Westport
Resources Corporation. 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]

A-8
<PAGE> 120

[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

[NSAI BOTTOM LETTERHEAD]
A-9
<PAGE> 121

[NSAI SHORT TOP LETTERHEAD]

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.

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.

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.

A-10
<PAGE> 122

[NSAI SHORT TOP LETTERHEAD]

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-11
<PAGE> 123

[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.

<TABLE>
<CAPTION>
As of January 1, 2000
----------------------------------------------------------
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-12
<PAGE> 124
Westport Oil and Gas Company Inc.
February 24, 2000
Page 2

The proved 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.

<TABLE>
<CAPTION>
Discounted Future Net
Income
As of January 1, 2000
----------------------------
Discount Rate Total
Percent Proved
------------- ------------
<S> <C>
8 $380,016,724
12 $322,519,383
15 $288,986,865
20 $245,403,934
</TABLE>

The results shown above are presented for your information and should not be
construed as our estimate of fair market value.

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. Our definitions
of proved reserves are included under the tab "Reserve Definitions" in this
report.

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.

A-13
<PAGE> 125
Westport Oil and Gas Company Inc.
February 24, 2000
Page 3

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.

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
A-14
<PAGE> 126
Westport Oil and Gas Company Inc.
February 24, 2000
Page 4

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).

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.

A-15
<PAGE> 127
Westport Oil and Gas Company Inc.
February 24, 2000
Page 5

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]

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[WESTPORT LOGO]