<PAGE>

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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

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


                          AMENDMENT NO. 1 TO FORM 10-K

                                       ON

                                  FORM 10-K/A

<Table>
<C>        <S>
(Mark One)
   [X]     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
           SECURITIES EXCHANGE ACT OF 1934

           FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                                  OR


   [ ]     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
           SECURITIES EXCHANGE ACT OF 1934

           FOR THE TRANSITION PERIOD FROM           TO        .
</Table>

                       COMMISSION FILE NUMBER: 001-14256
                         WESTPORT RESOURCES CORPORATION
             (Exact name of Registrant as specified in its charter)

<Table>
<S>                                            <C>
                    NEVADA                                       13-3869719
   (State of incorporation or organization)                   (I.R.S. Employer
                                                            Identification No.)
</Table>

                           1670 BROADWAY, SUITE 2800
                             DENVER, COLORADO 80202
                    (Address of principal executive offices)
                                   (Zip code)

              (REGISTRANT'S TELEPHONE NUMBER INCLUDING AREA CODE):
                                 (303) 573-5404

          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

<Table>
<Caption>
                    EACH CLASS                           NAME OF EACH EXCHANGE ON WHICH REGISTERED
                    ----------                           -----------------------------------------
<S>                                                 <C>
      Common Stock, par value $.01 per share                      New York Stock Exchange
6 1/2% Convertible Preferred Stock, par value $.01
                      per share                                   New York Stock Exchange
</Table>

          SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      NONE
                                (Title of class)

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

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

    Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).  Yes [X]    No [ ]

    The aggregate market value of the voting and non-voting common stock held by
non-affiliates of the Registrant as of June 28, 2002 (the last business day of
the Registrant's most recently completed second fiscal quarter) was
approximately $269,947,165. The number of shares of the Registrant's common
stock outstanding as of March 3, 2003, was 66,793,522.

                      DOCUMENTS INCORPORATED BY REFERENCE

    Parts of the definitive proxy statement for the Registrant's 2003 annual
meeting of stockholders are incorporated by reference into Part III of this Form
10-K.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                               TABLE OF CONTENTS


<Table>
<Caption>
                                                                        PAGE
                                                                        ----
<S>       <C>                                                           <C>
EXPLANATORY NOTE......................................................    2
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS.....................    2

ITEM NO.

                                   PART I


ITEM 1.   BUSINESS....................................................    3
ITEM 2.   PROPERTIES..................................................   25
ITEM 3.   LEGAL PROCEEDINGS...........................................   33
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........   33

                                  PART II


ITEM 5.   MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
          STOCKHOLDER MATTERS.........................................   34
ITEM 6.   SELECTED FINANCIAL DATA.....................................   35
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
          AND RESULTS OF OPERATIONS...................................   37
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
          RISK........................................................   51
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................   54
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
          AND FINANCIAL DISCLOSURE....................................   54

                                  PART III


ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........   55
ITEM 11.  EXECUTIVE COMPENSATION......................................   59
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
          MANAGEMENT..................................................   59
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............   60
ITEM 14.  CONTROL AND PROCEDURES......................................   62

                                  PART IV


ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
          8-K.........................................................   63
SIGNATURES............................................................   69
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS............................  F-1
</Table>


                                        1
<PAGE>

                                EXPLANATORY NOTE


     This Amendment No. 1 to our Annual Report on Form 10-K for the year ended
December 31, 2002, originally filed with the Securities and Exchange Commission
on March 10, 2003, is being filed to amend and restate the information required
by Part 1, Items 1 and 2, Part II, Items 6, 7 and 7A, and Part III, Items 10,
11, 12 and 13, to provide additional disclosures in Notes 1, 2, 4, 9, 14, 15 and
17 to our Consolidated Financial Statements, and to revise certain information
on Pages F-5, F-34 and F-44, in order to address certain comments received from
the Securities and Exchange Commission in connection with its review of our
Registration Statement on Form S-4 filed with the Securities and Exchange
Commission on June 4, 2003.


               SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     Our disclosure and analysis in this report, including information
incorporated by reference, includes forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, or Securities
Act, Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange
Act, and the Private Securities Litigation Reform Act of 1995, that are subject
to risks and uncertainties. Forward-looking statements give our current
expectations and projections relating to the acquisition, which closed on
December 17, 2002, of certain natural gas properties and midstream gathering and
compression assets located in Utah from certain affiliates of El Paso
Corporation, and the financial condition, results of operations, plans,
objectives, future performance and business of Westport Resources Corporation
and its subsidiaries. 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 expressions of similar meaning in connection with
any discussion of the timing or nature of future operating or financial
performance or other events. All statements other than statements of historical
facts included in this report that address activities, events or developments
that we expect, believe or anticipate will or may occur in the future are
forward-looking statements including, among other things, statements relating
to:

     - amount, nature and timing of capital expenditures;

     - amount,

     - projected drilling of wells;

     - reserve estimates;

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

     - operating costs and other expenses;

     - cash flow, anticipated liquidity and prospects for growth;

     - estimates of proved reserves and exploitation and exploration
       opportunities; and

     - marketing of oil and natural gas.

     These forward-looking statements are based on our expectations and beliefs
concerning future events affecting us and are subject to uncertainties and
factors relating to our operations and business environment, all of which are
difficult to predict and many of which are beyond our control. Although we
believe that the expectations reflected in our forward-looking statements are
reasonable, we do not know whether our expectations will prove correct. Any or
all of our forward-looking statements in this report 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 report, including the risks outlined under "Risk Factors," will be
important in determining future results. Actual future results may vary
materially. Because of these factors, we caution that investors should not place
undue reliance on any of our forward-looking statements. Further, any
forward-looking statement speaks only as of the date on which it is made, and
except as required by law we undertake no obligation to update any forward-
looking statement to reflect events or circumstances after the date on which it
is made or to reflect the occurrence of anticipated or unanticipated events or
circumstances.

                                        2
<PAGE>

                                     PART I

ITEM 1.  BUSINESS

ABOUT WESTPORT


     Unless otherwise indicated or the context otherwise requires, all
references in this report to "Westport," the "Company," "us," "our," or "we" are
to Westport Resources Corporation, a Nevada corporation, and its consolidated
subsidiaries. On December 17, 2002, we closed, effective as of June 1, 2002, the
acquisition, also referred to as the Acquisition, of certain natural gas
properties and midstream gathering and compression assets located in the Uinta
Basin, Utah, also referred to as the Acquired Properties, from certain
affiliates of El Paso Corporation. We have provided definitions for some of the
oil and natural gas industry terms used in this report in the "Glossary of Oil
and Natural Gas Terms" beginning on page 23.


     We are an independent energy company engaged in oil and natural gas
exploitation, acquisition and exploration activities primarily in the United
States. Based upon production levels during the fourth quarter of 2002, we are
among the 20 largest domestic independent exploration and production companies.
Our reserves and operations are concentrated in the following divisions:
Northern, which primarily includes properties in North Dakota and Wyoming;
Western, which includes the Acquired Properties in the Uinta Basin; Southern,
which primarily includes properties in Oklahoma, Texas and Louisiana; and Gulf
of Mexico, which includes our offshore properties. 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.

     On December 17, 2002, we closed, effective as of June 1, 2002, the
Acquisition of producing properties, undeveloped leasehold, gathering and
compression facilities and other related assets in the Greater Natural Buttes
area of Uintah County, Utah for approximately $507 million. The Greater Natural
Buttes field is a core asset with a reserve to production ratio of over 20
years. The Acquisition increased our reserves by approximately 60%, raised
production by approximately 19% and replaced nearly 459% of our 2002 production.
The Acquired Properties contain over 600 proved undeveloped locations, with
additional exploitation and exploration opportunities on our 244,000 net acres
of leasehold.


     In addition to our acquisition activity, we successfully executed a series
of capital market transactions, refinanced our revolving credit facility to
expand our borrowing capacity by approximately 17% and increased our shareholder
float by approximately 89%. These transactions include the private offering of
$300 million of our 8 1/4% Senior Subordinated Notes Due 2011, at an effective
yield of approximately 7 5/8%, which we completed in December 2002.
Concurrently, we closed the public offering of 11.5 million shares of our common
stock at a price of $19.90 per share. These two transactions together generated
net proceeds of approximately $517 million, which were used to fund the
Acquisition. In December 2002, we also entered into a credit facility, as
amended on October 15, 2003, also referred to as the Revolving Credit Facility,
with JPMorgan Chase Bank, Credit Suisse First Boston Corporation and certain
other lenders party thereto to replace our previous revolving credit facility.
The Revolving Credit Facility provides for a maximum committed amount of $600
million, with an initial borrowing base of approximately $470 million and a
maturity date of December 16, 2006. In November 2002, we completed a private
placement of 3.125 million shares of our common stock to certain qualified
institutional buyers at a net price to us of $16.00 per share and received
aggregate proceeds of $50 million in connection with this transaction.


     Over the last several years acquisitions and subsequent exploitation have
fueled growth in our reserves, production and cash flow. From December 31, 1997
to December 31, 2002, we increased our estimated proved reserves from 197 Bcfe
to 1,580 Bcfe, a compounded annual growth rate of approximately 52%. Over the
same period we increased average daily production from 66 Mmcfe/d to 356
Mmcfe/d, a compounded annual growth rate of approximately 40%. This increased
our reserve to production ratio from approximately 7 years to approximately 10
years. Our reserve and production growth has been complemented by consistent
reductions in our per unit cost structure over the same period from $1.32 per

                                        3
<PAGE>


Mcfe to $1.12 per Mcfe of our net production for lease operating expenses,
transportation costs, production taxes and general and administrative costs. For
the twelve months ended December 31, 2002, we generated oil and natural gas
sales of approximately $428 million.


     We believe that our exploration and exploitation inventory and our
acquisition expertise, together with our operating experience and cost
structure, provide us with the ability to generate substantial current cash flow
and position us for future growth. We operate approximately 77% of the net
present value of our reserves, allowing us to better manage expenses, capital
allocation and the decision-making processes related to all aspects of
exploitation and exploration activities. Our capital expenditures for 2002 were
approximately $163.5 million, which does not include acquisitions. We expect
that our total 2003 capital budget, excluding acquisitions, will be
approximately $230 million, 75% of which has been allocated to exploitation. We
anticipate drilling between 275 and 350 wells during 2003.

     As of December 31, 2002, our estimated proved reserves of 1,580 Bcfe had a
pre-tax net present value, discounted at 10%, of approximately $2.4 billion
based on year end NYMEX prices of $31.23 per barrel of oil and $4.58 per Mmbtu
of natural gas. Approximately 66% of our reserves were classified as proved
developed as of December 31, 2002. The following table sets forth the volume and
net present value of our estimated proved reserves as of December 31, 2002 and a
summary of our fourth quarter 2002 production by division:

<Table>
<Caption>
                                                                       AT DECEMBER 31, 2002
                                             ------------------------------------------------------------------------
                                                                                                  NET PRESENT VALUE
                          QUARTER ENDED                  PROVED RESERVE QUANTITIES                  BEFORE INCOME
                       {DECEMBER 31, 2002    -------------------------------------------------         TAXES(2)
                        AVERAGE NET DAILY                                                        --------------------
                           PRODUCTION                                  NATURAL GAS
                       -------------------   CRUDE OIL   NATURAL GAS     LIQUIDS       TOTAL       AMOUNT
DIVISION               MMCFE/D    PERCENT     (MMBBL)       (BCF)        (MMBBL)     (BCFE)(1)   (MILLIONS)   PERCENT
--------               --------   --------   ---------   -----------   -----------   ---------   ----------   -------
<S>                    <C>        <C>        <C>         <C>           <C>           <C>         <C>          <C>
Northern.............    107.3      28.5%      34.3          146.9          --          352.9     $  514.9      21.4%
Western(3)...........     11.1       2.9%       1.2          589.3          --          596.1        554.7      23.1%
Southern.............    150.6      40.0%      36.7          255.4          --          475.6        876.9      36.4%
Gulf of Mexico.......    107.5      28.6%       7.0          109.8         0.5          155.0        459.3      19.1%
                        ------     -----       ----        -------         ---        -------     --------     -----
     Total...........    376.5     100.0%      79.2        1,101.4         0.5        1,579.6     $2,405.8     100.0%
                        ======     =====       ====        =======         ===        =======     ========     =====
</Table>

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

(1) Mmbbls converted to Bcfe at a six to one conversion.

(2) Excludes value attributable to the gathering and compression assets of
    Westport Field Services, LLC, one of our subsidiaries.

(3) Includes production from the Acquisition closing date of December 17, 2002
    through December 31, 2002.

OUR STRATEGY

     Our strategy is to grow our reserve base and production, maintain our
diversified risk profile and expand our investment opportunities primarily by
executing on lower-risk exploitation projects and acquisitions. Although our
emphasis is on exploitation and acquisition activities, we will continue
drilling potentially higher-impact exploration prospects, thereby balancing
risks while maintaining significant potential for growth. To accomplish this
strategy, we will:

     - enhance our exploitation activity by allocating approximately 75% of our
       capital budget to exploitation to increase production and enhance our
       reserve base;

     - continue our acquisition activity to achieve greater immediate cash flow
       and expand our exploitation inventory;

     - continue to generate and drill an extensive prospect inventory by
       applying current technology and leveraging our significant operational
       capabilities and acreage inventory; and

                                        4
<PAGE>

     - maintain financial flexibility and a conservative capital structure
       through prudent financial and hedging activities.

COMPANY HISTORY

     Westport was formed by the merger on April 7, 2000 of Westport Oil and Gas
Company, Inc., which we refer to as Westport Oil and Gas, and Equitable
Production (Gulf) Company, which we refer to as EPGC, an indirect, wholly owned
subsidiary of Equitable Resources, Inc. As a result of the merger, Westport Oil
and Gas became a wholly owned subsidiary of EPGC, which subsequently changed its
name to Westport Resources Corporation, and the stockholders of Westport Oil and
Gas became the majority stockholders of EPGC. 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 between EPGC and
Westport Oil and Gas was accounted for using purchase accounting with Westport
Oil and Gas as the surviving accounting entity. Westport began consolidating the
results of EPGC with the results of Westport Oil and Gas as of the April 7, 2000
closing date.

     On August 21, 2001, the stockholders of Belco Oil and Gas Corp., or Belco,
approved an agreement and plan of merger, dated as of June 8, 2001, between
Belco and Westport. Pursuant to this agreement, Westport was merged with and
into Belco, with Belco surviving and changing its name to Westport Resources
Corporation. The merger was accounted for as a purchase transaction for
financial accounting purposes with Westport as the surviving accounting entity.
Westport began consolidating the results of Belco with its results as of the
August 21, 2001 closing date.

     We are incorporated under the laws of the State of Nevada. Our principal
offices are located at 1670 Broadway Street, Suite 2800, Denver, Colorado 80202.
Our telephone number is (303) 573-5404, and our web site can be found at
www.westportresourcescorp.com.

PURCHASERS AND MARKETING

     Our oil and natural gas production is principally sold to 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 2002, our
largest purchaser was Conoco Inc., which accounted for 10% of our oil and
natural gas sales. No other purchasers accounted for more than 10% of our oil
and natural gas sales. We do not believe, however, that the loss of any of our
purchasers would have a material adverse effect on our operations.

     We periodically enter into commodity derivative contracts (future
contracts, swaps or options) in order to (i) reduce the effect of the volatility
of price changes on the commodities we produce and sell, (ii) support our annual
capital budgeting and expenditure plans and (iii) lock in prices to protect the
economics related to certain capital projects. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" for a
description of our hedging activities, "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" and Note 3 of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
information concerning the impact to revenues during 2002, 2001 and 2000 from
our commodity derivative activities, our open derivative positions and related
prices.

SEASONALITY

     Demand for natural gas has historically been seasonal, with peak demand and
typically higher prices occurring during the colder winter months.

COMPETITION

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

                                        5
<PAGE>

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 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,
or NGA, the Natural Gas Policy Act of 1978 and the regulations promulgated there
under by the Federal Energy Regulatory Commission, or the FERC. 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 NGA 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 FERC 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 FERC 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.

     In subsequent action, the FERC issued Order No. 637 and a series of related
orders, which are intended to institute incremental reforms to the Order No. 636
regulatory model. The FERC's stated purpose in Order No. 637 is to "improve the
efficiency of the market and to provide captive customers with the opportunity
to reduce their cost of holding long-term pipeline capacity while continuing to
protect against the exercise of market power." Order No. 637, among other
things, (i) removed price caps on short-term (less than 12 months in duration)
capacity release transactions through September 30, 2002, (ii) authorizes
pipelines to implement peak and off-peak rates for short-term services and term-
differentiated rates, (iii) requires pipelines to offer enhanced imbalance
management services and to implement netting and trading of transportation
imbalances, (iv) limits the use of pipeline penalties, and (v) provides
increased transparency through enhanced posting of transactional information on
pipelines' websites. Order No. 637 was implemented through compliance filings by
pipelines, on which shippers were afforded the opportunity to comment. The FERC
has now issued a number of orders in pipeline compliance proceedings, resolving
most of the issues raised by the compliance filings. Pipeline interests and
other parties challenged certain aspects of Order No. 637 on judicial review. In
a decision issued in 2002, the U.S. Court of Appeals for the District of
Columbia Circuit upheld almost all material aspects of Order No. 637.

     The Outer Continental Shelf Lands Act, or OCSLA, requires that all
pipelines operating on or across the Outer Continental Shelf, or OCS, provide
open-access, nondiscriminatory service. In mid-2000, the FERC issued Order Nos.
639 and 639-A, imposing reporting requirements on gas pipelines operating on the
OCS that are not subject to regulation under the NGA. The stated purpose of
these reporting

                                        6
<PAGE>

requirements is to provide transparency for shippers on OCS gas pipelines in
order to aid in detecting discriminatory conduct. Pipeline interests challenged
the reporting requirements before the U.S. District Court for the District of
Columbia on the ground that Congress did not delegate rulemaking authority to
the FERC to implement the nondiscrimination requirement in Section 5(f) of the
OCSLA. In January 2002, the District Court ruled in the pipelines' favor,
entering a permanent injunction against the OCS pipeline reporting requirements.
The FERC and certain producer/shipper interests have now appealed to the U.S.
Court of Appeals for the D.C. Circuit. The case has now been briefed and will
likely be argued to the Court before summer with a decision expected before
year-end. If it is ultimately determined on judicial review that the FERC does
not have authority to implement reporting requirements for OCS pipelines, it
will be difficult for producers on the OCS to enforce the nondiscrimination
requirement in the statute, thus raising the possibility of increased
discriminatory conduct by OCS gas pipelines.

     Commencing in May 1994, the FERC issued a series of orders that, among
other matters, slightly broadened the types of facilities that would be found to
be non-jurisdictional gathering facilities and reaffirmed that, except in
situations in which the gatherer acts in concert with an interstate pipeline
affiliate to frustrate the FERC's transportation policies, 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 FERC action may further encourage
regulatory scrutiny of natural gas gathering by state agencies. We do not
believe that we will be affected by these developments any differently than
other natural gas producers, gatherers and marketers.

     Concurrently with the transfer of gathering facilities onshore, a number of
interstate pipelines requested authority to have their facilities on the OCS
declared a non-jurisdictional gathering. Many of the pipelines on the OCS are
large-capacity lines that move up to one Bcf of gas per day. Although the
jurisdictional test for OCS facilities is somewhat different from the test used
onshore, the general trend since 1994 has been toward an increasing number of
facilities being viewed as non-jurisdictional gathering by the FERC. A major
test case involving the Sea Robin Pipeline system was decided by a panel of the
U.S. Court of Appeals for the D.C. Circuit in August 2002. A two-judge majority
upheld the FERC's "central point of aggregation" test for determining
jurisdictional status of OCS pipelines. Under that test, the dividing line
between non-jurisdictional gathering and jurisdictional transportation is
generally identified as being located at the last major fork on the pipeline
before it goes onshore. Producer interests have now sought review of the D.C.
Circuit's decision in the United States Supreme Court. Action on the petitions
for writs of certiorari is expected by mid-2003. If the D.C. Circuit's decision
stands, producers on the OCS could be exposed to higher rates for gathering
services over former jurisdictional facilities downstream of production
platforms.

     In a related development, the FERC addressed a complaint by an OCS gas
producer in 2002 stemming from the transfer by an interstate pipeline of
formerly jurisdictional facilities on the OCS to a non-regulated gathering
affiliate. Soon after receiving the facilities, the non-regulated affiliate
instituted a three-fold rate increase to certain shippers. In an order issued in
September 2002, the FERC determined that the gathering affiliate and the
interstate pipeline had acted in concert to frustrate the effective regulation
of transportation of natural gas interstate commerce on the pipeline. The FERC
reasserted jurisdiction over the gathering affiliate and directed it to
institute a prospective reduction in rates to a cost-of-service rate. The FERC's
order is now being challenged on rehearing by the interstate pipeline and its
gathering affiliate. Because the FERC's order involves an untested legal theory,
it is difficult to predict the extent to which the FERC will be permitted to
reassert jurisdiction over former jurisdictional facilities that have been found
to be used for non-jurisdictional gathering.

     If the FERC ultimately decides that it should regulate fewer OCS facilities
under the NGA and such determination is upheld on judicial review, or if it is
determined that the FERC's jurisdiction over crude oil and natural gas
transportation on the OCS is more limited than previously asserted, we could
face higher transmission costs for our OCS natural gas production and, possibly,
reduced access to OCS transmission capacity. Upon the successful development of
our offshore exploration projects, we expect to own and operate facilities that
we believe will be gathering lines. If the FERC should decide to classify lines
on the OCS that traditionally have been viewed as gathering lines as
jurisdictional transmission lines,

                                        7
<PAGE>

our OCS facilities could be subject to regulation as interstate pipelines.
However, given the limited scope of such facilities, it is not expected that
such regulation would have a material impact on our operations or business.

     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 FERC 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 Bureau of Land
Management (onshore) and Minerals Management Service (offshore) of the U.S.
Department of the Interior and other agencies. Such leases are issued through
competitive bidding, contain relatively standardized terms and require
compliance with detailed Bureau of Land Management and Minerals Management
Service regulations and orders pursuant to the Mineral Lands Leasing Act, OCSLA
and other Federal statutes (which are subject to interpretation and change by
the agencies charged with their administration).

     For offshore operations, lessees must obtain Minerals Management Service,
or MMS, 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 MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications. The MMS also has regulations
restricting the flaring or venting of natural gas, and prohibiting the flaring
of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS
has promulgated other regulations governing the plugging and abandonment of
wells located offshore and the installation and removal of all production
facilities. To cover the various obligations of lessees on the Outer Continental
Shelf, the MMS 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 MMS may require any of our operations on Federal leases to be
suspended or terminated. Any such suspension or termination could materially
adversely affect our financial condition and results of operations.

     The United States Department of Transportation, or DOT, through its Office
of Pipeline Safety, also imposes certain requirements on parties responsible for
transportation pipelines associated with platforms located on the OCS. The MMS
and DOT have entered into a Memorandum of Understanding regarding the agencies'
respective authority over offshore operations, and the MMS has adopted
regulations implementing the Memorandum of Understanding by specifying the
dividing point for any given pipeline where MMS regulatory authority ends and
DOT authority begins.

     The MMS has entered into a series of Memoranda of Understanding with other
Federal agencies, such as the Environmental Protection Agency, Coast Guard and
Occupational Safety and Health Administration, providing for the MMS to
undertake certain inspection and, in some cases, enforcement responsibility for
the respective regulatory mandates of these agencies. Those agencies do,
however, retain varying degrees of jurisdiction over OCS operations to establish
and enforce regulatory requirements.

     In 1997, the MMS modified its regulations to, among other things, (i)
impose the duty on any lessee of an offshore lease to meet end-of-lease
obligations if the designated operator is unable to do so, (ii) establish joint
and several liability for plugging and abandonment of wells, removal of
platforms and other facilities, and clearance of well and platform locations,
among OCS lessees, assignees and assignors, thus creating residual liability in
certain parties for these obligations, (iii) increase the level of bond coverage
for drilling deep stratigraphic test wells and (iv) allow the MMS Regional
Director to require, on a case-by-case basis, posting of additional bonds or
other security in order to increase the amount of coverage for end-of-lease
obligations or certain other operations. These requirements may operate to
substantially increase our current bonding liabilities, and to also impact our
residual liabilities, both with

                                        8
<PAGE>

respect to existing leases acquired from third parties and with respect to
leases that we may acquire or dispose of in the future.

     Effective June 1, 2000, the MMS adopted regulations that changed
significantly the valuation of crude oil for royalty payments on onshore and
offshore Federal leases. These rules retained the concept of gross proceeds for
calculating royalties on production sold to third parties in arm's-length
transactions. However, oil sold in non-arm's-length contracts is to be valued
using index pricing methods or other benchmarking procedures to determine a
deemed arm's-length price. The rules define non-arm's-length sales to include
sales to affiliates, certain exchange transactions, sales pursuant to certain
call provisions, and other transactions. The breadth of these definitions could
cause certain sales by us to be impacted and could in some cases require that we
pay royalty on a deemed value higher than that which we actually receive for our
oil. These regulations have been challenged judicially.

     In a series of regulations and rulings over the past several years, the MMS
has also taken an expansive view of the lessee's duty to market natural gas on
behalf of the Federal government as lessor. For example, one of the rules has
disallowed the deductibility of certain transportation costs from the
calculation of royalty on gas sold off Federal leases, including marketer fees,
cash out and other pipeline imbalance penalties and long-term storage fees.
Although these regulations and rulings have been challenged judicially, that
challenge was rejected in large part. The impact of these regulations and
rulings could be to increase our costs of marketing production from Federal
leases and in effect impose royalty obligations on certain downstream sale
transactions.

     The MMS has also previously proposed gas valuation rules similar to those
described above for oil royalty valuation that would value gas sold in certain
non-arm's length transactions in accordance with defined indices or other
benchmarks. Those proposed rules were withdrawn in 1997, and it is not known
whether the MMS intends to reissue them. The potential effect of such rules, as
with the revised oil royalty valuation rules, would be to move the valuation
point downstream for purposes of royalty calculation and thereby to impose a
royalty obligation on a deemed value higher than proceeds realized by the lessee
from sales netted back to the wellhead. Although we do not have marketing
affiliates and do not currently market our production in exchanges or other
transactions that appear to be the target of these regulatory proposals, we
cannot predict how the final form of any of these rules could impact our royalty
obligations.

     STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION.  We own interests in
properties located in the Louisiana state waters off the Gulf of Mexico and on
state lands in the states in which we operate. We also own interests on private
lands that are subject to regulation by state and local governments.

     State regulations govern operational matters such as permits and bonds for
drilling, reclamation and plugging, spacing and pooling of wells, and reporting
requirements. The states in which we operate or plan to operate also have a
variety of statutes and regulations governing conservation matters, ranging from
establishment of maximum rates of production from oil and gas wells to the
proration of production to the market demand for oil and gas to the limitation
on ceiling prices for gas sold within the state. Such regulation could be
applied to restrict the rate at which our wells produce oil or gas below the
rate at which such wells would otherwise be produced, and the amount or timing
of our revenues could thereby be adversely affected.

     Also in recent years, pressure has increased in states in which we have
been active to increase regulation of the oil and gas industry at the local
government level. Such local regulation in general is aimed at increasing the
involvement of local governments in the permitting of oil and gas operations,
requiring additional restrictions or conditions on the conduct of operations to
reduce the impact on the surrounding community and increasing financial
assurance requirements. Accordingly, such regulation has the potential to delay
and increase the cost, or even in some cases to prohibit entirely, the conduct
of our drilling activities.

                                        9
<PAGE>

     Substantially all of the Acquired Properties are located within the Uintah
and Ouray Indian Reservation. As a result, our interests and operations therein
may be subject to the jurisdiction of various Tribal authorities.

     OIL PRICE CONTROLS AND TRANSPORTATION RATES.  Our sales of crude oil,
condensate and natural gas liquids are not currently regulated and are made at
market prices. Effective as of January 1, 1995, the FERC 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 oil 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.

     The drilling for and production, handling, transportation and disposal of
oil and gas and by-products are subject to extensive regulation under Federal,
state and local environmental laws. In most instances, the applicable regulatory
requirements relate to water and air pollution control and oilfield management
measures, permitting requirements, or restrictions on operations in
environmentally sensitive areas such as coastal zones, wetlands and wildlife
habitat. These requirements increase our cost of doing business, delay or
preclude operations, and create potential liability to governmental agencies or
third parties for environmental damage. For example, environmental regulation
may in some circumstances impose "strict liability" for environmental
contamination, rendering an owner or operator or other person with a connection
to a property liable for environmental and natural resource damages and cleanup
cost without regard to negligence or fault on the part of such person. In
addition, state laws often require some form of remedial action to prevent
pollution from former operations, such as closure of inactive pits and plugging
of abandoned wells, and such liability can be imposed on successor owners. In
connection with our acquisitions, we generally perform environmental
assessments. To the extent environmental liabilities have been identified, such
liabilities are not material or we have negotiated agreements requiring the
sellers of the properties to undertake the required clean-up. We have assumed
responsibility for some of these matters identified. Environmental assessments
have not been performed on all of our properties.

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

     The Oil Pollution Act of 1990, or OPA, 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. The OPA assigns
liability to "responsible parties" for oil removal costs and a variety of public
and private damages. 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. Few defenses exist to the liability imposed
by the OPA.

                                        10
<PAGE>

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 OPA 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.

     The Federal Water Pollution Control Act, or FWPCA, imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and gas
wastes into navigable waters. Permits must be obtained to discharge pollutants
to waters and to conduct construction activities in waters and wetlands. The
FWPCA and similar state laws provide for civil, criminal and administrative
penalties for any unauthorized discharges of pollutants and unauthorized
discharges of reportable quantities of oil and other hazardous substances. Many
state discharge regulations and the Federal National Pollutant Discharge
Elimination System generally limit and may otherwise prohibit the discharge of
produced water and sand, drilling fluids, drill cuttings and certain other
substances related to the oil and gas industry into coastal or offshore waters.
Although the costs to comply with zero discharge mandates under Federal or state
law may be significant, the entire industry is expected to experience similar
costs and we believe that these costs will not have a material adverse impact on
our results of operations or financial position. In 1992, the Environmental
Protection Agency adopted regulations requiring certain oil and gas exploration
and production facilities to obtain permits for storm water discharges, carrying
costs associated with the treatment of wastewater or developing and implementing
storm water pollution prevention plans.

     The Endangered Species Act, or ESA, seeks to ensure that activities do not
jeopardize endangered or threatened animal, fish and plant species, nor destroy
or modify the critical habitat of such species. Under the ESA, seismic,
exploration and production operations, as well as actions by Federal agencies,
may not significantly impair or jeopardize the species or its habitat. The ESA
provides for criminal penalties for willful violations of the Act. Other
statutes provide protection to animal and plant species and may apply to our
operations, such as the Marine Mammal Protection Act, the Migratory Bird Treaty
Act, and the National Historic Preservation Act.

     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 costs of such activities have not been material.
However, we could incur significant costs 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 OCSLA. We may
be required to incur capital expenditures to upgrade pollution control equipment
or become liable for non-compliance with applicable permits.

     New initiatives regulating the disposal of oil and gas waste are also
pending or have been enacted in certain states, including states in which we
conduct operations, and these various initiatives could have a similar impact on
us. These rules establish significant permitting, record-keeping and compliance
procedures that may require the termination of production from marginal wells
for which the cost of compliance would exceed the value of remaining production
and could lead to the incurring of significant remediation costs for properties
found to have caused groundwater contamination or other environmental problems.

     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.

                                        11
<PAGE>

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.

TITLE TO PROPERTIES

     As is customary in the oil and natural gas industry, we make only a cursory
review of title to farmout acreage and to onshore undeveloped oil and natural
gas leases upon execution of contracts for acquisition of leases. Prior to the
commencement of drilling operations, a thorough title examination is conducted
and curative work is performed with respect to significant defects. We perform
complete reviews of title to Federal and state offshore lease blocks and onshore
producing properties prior to acquisition. To the extent title opinions or other
investigations reflect material title defects, the seller of the property,
rather than us, is typically responsible for curing any such title defects at
its expense. If we were unable to remedy or cure any title defect of a nature
such that it would not be prudent to commence drilling operations on undeveloped
properties, we could suffer a loss of our entire investment in the property. We
have obtained title opinions on substantially all of our producing properties
and believe that we have satisfactory title to such properties in accordance
with standards generally accepted in the oil and gas industry. Our producing
properties are subject to a negative pledge in connection with our Revolving
Credit Facility.

ABANDONMENT COSTS

     We are responsible for costs associated with the plugging of wells, the
removal of facilities and equipment and site restoration on our oil and natural
gas properties, pro rata to our working interest. As of January 1, 2003 we
adopted SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143
requires entities to record the fair value of liabilities for retirement
obligations of acquired assets. We expect to record asset retirement obligations
of approximately $59 million and a cumulative effect of change in accounting
principle on prior years in the range of $2 million to $5 million in our
consolidated statement of operations on January 1, 2003. Estimates of
abandonment costs and their timing may change due to many factors, including
actual drilling and production results, inflation rates, and changes in
environmental laws and regulations. Estimated asset retirement obligations are
added to net unamortized historical oil and gas property costs for purposes of
computing depreciation, depletion and amortization expense charges.

EMPLOYEES

     At December 31, 2002, we had 333 full-time employees. 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.

                                        12
<PAGE>

RISK FACTORS


     This section describes the material risks known to us that may adversely
impact our operations and financial results. We encourage you to consider such
risks in evaluating our business and future prospects. In addition, we urge you
to perform your own investigation with respect to us and our business. We also
encourage you to read the other information included in this report, including
our financial statements and the related notes.


  OIL AND NATURAL GAS PRICES FLUCTUATE WIDELY, AND LOW PRICES COULD HARM OUR
  BUSINESS.


     Our results of operations are highly dependent upon the prices of oil and
natural gas. Historically, oil and natural gas prices have been volatile and are
likely to continue to be volatile in the future. For example, our average sales
prices for oil and natural gas for the year ended December 31, 2002 were
$23.66/bbl and $2.93/Mcf, respectively, with production totaling 129.9 Bcfe and
combined oil and natural gas sales of $428.4 million during this period. In
contrast, our average sales prices for oil and natural gas for the year ended
December 31, 2001 were $21.69/bbl and $3.59/Mcf, respectively, with production
totaling 88.1 Bcfe and combined oil and natural gas sales of $317.3 million
during this period. The prices received for oil and natural gas production
depend upon numerous factors including, among others:


     - consumer demand;

     - governmental regulations and taxes;

     - the price and availability of alternative fuels;

     - geopolitical developments, including potential military activity in the
       Middle East;

     - commodity processing, gathering and transportation availability;

     - the level of foreign imports of oil and natural gas; and

     - the overall economic environment.

All of these factors are beyond our control. Any significant decrease in prices
for oil and natural gas could have a material adverse effect on our financial
condition, results of operations and quantities of reserves that are
commercially recoverable. For example, the decline in oil and natural gas prices
over the past year has impacted our cash flow and could adversely impact our
borrowing base and liquidity in general. If the oil and natural gas industry
continues to experience significant future price decreases or other adverse
market conditions, we may not be able to generate sufficient cash flow from
operations to meet our obligations and make planned capital expenditures.


  OUR REVENUES MAY BE INSUFFICIENT TO FUND OUR OPERATIONS, WHICH MAY RESULT IN A
  DECREASE IN PRODUCTION OVER TIME.


     We expect for the foreseeable future to make substantial capital
expenditures for the acquisition, exploration and development of oil and natural
gas reserves. Historically, we have paid for these expenditures primarily with
cash from operating activities and with proceeds from debt and equity
financings. If revenues decrease as a result of lower oil and natural gas prices
or for any other reason, we may not have the funds available to replace our
reserves or to maintain production at current levels, which would result in a
decrease in production over time.

  OUR FORMER INDEPENDENT PUBLIC ACCOUNTANT, ARTHUR ANDERSEN LLP, HAS BEEN FOUND
  GUILTY OF A FEDERAL OBSTRUCTION OF JUSTICE CHARGE, AND YOU MAY BE UNABLE TO
  EXERCISE EFFECTIVE REMEDIES AGAINST IT IN ANY LEGAL ACTION.

     Our former independent public accountant, Arthur Andersen LLP, provided us
with auditing services for prior fiscal periods through December 31, 2001,
including issuing an audit report to our audited consolidated financial
statements included in this report. On June 15, 2002, a jury in Houston, Texas
found Arthur Andersen LLP guilty of a Federal obstruction of justice charge
arising from the Federal Government's investigation of Enron Corp. On August 31,
2002, Arthur Andersen LLP ceased practicing

                                        13
<PAGE>

before the SEC. Arthur Andersen LLP has not reissued its audit report with
respect to our audited consolidated financial statements included in this
report. Furthermore, Arthur Andersen LLP has not consented to the inclusion of
its audit report in this report. As a result, you may not have an effective
remedy against Arthur Andersen LLP in connection with a material misstatement or
omission with respect to our audited consolidated financial statements that are
included in this report or any other filing we may make with the SEC, including,
with respect to any offering registered under the Securities Act, any claim
under Section 11 of the Securities Act. In addition, even if you were able to
assert such a claim, as a result of its conviction and other lawsuits, Arthur
Andersen LLP may fail or otherwise have insufficient assets to satisfy claims
made by investors or by us that might arise under Federal securities laws or
otherwise relating to any alleged material misstatement or omission with respect
to our audited consolidated financial statements.

     In addition, in connection with any future capital markets transaction in
which we are required to include financial statements that were audited by
Arthur Andersen LLP, as a result of the foregoing, investors may elect not to
participate in any such offering or, in the alternate, may require us to obtain
a new audit with respect to previously audited financial statements.
Consequently, our financing costs may increase or we may miss attractive capital
market opportunities.

  OUR LEVERAGE AND DEBT SERVICE OBLIGATIONS MAY ADVERSELY AFFECT OUR CASH FLOW
  AND OUR ABILITY TO MAKE PAYMENTS ON OUR LONG-TERM DEBT.


     As of December 31, 2002, we had total long-term debt of approximately
$799.4 million and stockholders' equity of approximately $1.1 billion. Our level
of debt could have important consequences to our business, including the
following:


     - it may be more difficult for us to satisfy our debt repayment
       obligations;

     - we may have difficulties borrowing money in the future for acquisitions,
       to meet our operating expenses or other purposes;

     - the amount of our interest expense may increase because certain of our
       borrowings are at variable rates of interest, which, if interest rates
       increase, could result in higher interest expense;

     - we will need to use a portion of the money we earn to pay principal and
       interest on our debt which will reduce the amount of money we have to
       finance our operations and other business activities;

     - we may have a higher level of debt than some of our competitors, which
       may put us at a competitive disadvantage;

     - we may be more vulnerable to economic downturns and adverse developments
       in our industry; and

     - our debt level could limit our flexibility in planning for, or reacting
       to, changes in our business and the industry in which we operate.


  ANY FAILURE TO MEET OUR DEBT OBLIGATIONS COULD HARM OUR BUSINESS, FINANCIAL
  CONDITION AND RESULTS OF OPERATIONS.



     Our ability to meet our expenses and debt obligations will depend on our
future performance, which will be affected by financial, business, economic,
regulatory and other factors. We will not be able to control many of these
factors, such as economic conditions and governmental regulation. Our earnings
may be insufficient to allow us to pay the principal and/or interest on our debt
and meet our other obligations. If we do not have enough money, we may be
required to refinance all or part of our existing debt, sell assets, borrow more
money or raise equity. We may not be able to refinance our debt, sell assets,
borrow more money or raise equity on terms acceptable to us, if at all. In
addition, any failure to make scheduled payments of interest and/or principal on
our outstanding indebtedness would likely result in a reduction of our credit
rating, which could harm our ability to incur additional indebtedness on
acceptable terms.


                                        14
<PAGE>


     Further, our failure to make scheduled payments on our outstanding
indebtedness or our failure to comply with the financial and other restrictive
covenants in our debt instruments could result in an event of default under such
instruments. Such a default, or any bankruptcy resulting therefrom, could result
in a default on the notes, could delay or preclude payment of principal of, or
interest on, the notes and could otherwise adversely affect our business,
financial condition and results of operations.



  WE MAY BE ABLE TO INCUR SUBSTANTIALLY MORE DEBT. ADDITIONAL DEBT COULD
  EXACERBATE THE RISKS DESCRIBED ABOVE.



     Together with our subsidiaries, we may be able to incur a substantial
amount of debt in the future. The restrictions in the indenture governing terms
of our debt relating to the incurrence of indebtedness are subject to a number
of qualifications and exceptions, and under certain circumstances, indebtedness
incurred in compliance with these restrictions could be substantial. Also, these
restrictions do not prevent us from incurring obligations that do not constitute
indebtedness. As of December 31, 2002, we had approximately $372.9 million of
additional borrowing capacity under our Revolving Credit Facility, subject to
specific requirements, including compliance with financial covenants. To the
extent new debt is added to our current debt levels, the risks described above
could substantially increase.


  INDIAN TRIBES HAVE PREVIOUSLY CHALLENGED THE VALIDITY OF SOME OF THE PROPERTY
  INTERESTS COVERED BY OIL AND NATURAL GAS LEASES IN THE AREA IN WHICH THE
  ACQUIRED PROPERTIES ARE LOCATED, AND OUR OPERATIONS AND ACTIVITIES ON TRIBAL
  LANDS MAY BE SUBJECT TO TRIBAL JURISDICTION.


     Substantially all of the oil and natural gas leases we acquired in the
Acquisition cover interests located within the Uintah and Ouray Indian
Reservation, in an area originally known as the Umcompahgre Reservation. These
leases were granted by the State of Utah, the United States (through the Bureau
of Land Management) or holders of patents from the United States. The Ute Indian
Tribe has previously asserted various claims against the State of Utah and the
United States regarding the existence, diminishment and/or abrogation of the
Reservation's boundaries and the extent of Tribal jurisdiction over these lands.
These lawsuits raised questions as to whether the Ute Tribe could invalidate
through litigation fee patents issued by the United States, the State of Utah's
ownership of such lands or the United States' ownership of minerals subject to
the acquired leases. These issues were settled as a result of the Ute Indian
Tribe litigation. If claims of this nature were successfully asserted in the
future, we might not be able to continue to produce hydrocarbons from or develop
and exploit these assets, which could adversely affect our business and
profitability.


     In addition, the Ute Indian Tribe as a sovereign nation has certain rights
to regulate activities on Tribal lands, to approve access to and the right to
use (occupy) Tribal lands, and to tax revenues from Tribal resources. Exercise
of such rights can result in potential delays or increased costs to our
operations on Tribal lands which may not be foreseeable.

  THE GEOGRAPHIC CONCENTRATION OF THE ACQUIRED PROPERTIES IN UTAH SUBJECTS US TO
  INCREASED RISK OF REDUCTION IN REVENUES OR CURTAILMENT OF PRODUCTION FROM
  CERTAIN NEGATIVE CONDITIONS.

     All of the Acquired Properties are located in Uintah County, Utah.
Conditions such as severe weather, delays or decreases in production, the
availability of equipment, facilities or services or the availability of
capacity to transport, gather or process production could subject us to
increased risk of loss of revenues and have a greater impact on our results of
operations since most or all of the Acquired Properties could be affected by the
same event.

  WE MAY NOT REALIZE THE ANTICIPATED BENEFITS FROM THE ACQUISITION.

     Our estimates regarding the expenses and liabilities or the increase in our
reserves and production resulting from the Acquisition may prove to be incorrect
or we may not be successful in integrating the Acquired Properties into our
existing business, all of which could have a material adverse effect on the
financial condition and results of operations.

                                        15
<PAGE>

  WE MAY NOT BE ABLE TO CONSUMMATE FUTURE ACQUISITIONS OR SUCCESSFULLY INTEGRATE
  ACQUISITIONS INTO OUR BUSINESS.

     Our business strategy includes growing our reserve base through
acquisitions. We may not continue to be successful in identifying or
consummating future acquisitions or integrating acquired businesses successfully
into our existing business, or in anticipating the expenses or liabilities we
will incur in doing so. Such failures may have a material adverse effect on
future growth or results of operations.

     We are continually investigating opportunities for acquisitions. In
connection with future acquisitions, the process of integrating acquired
operations into our existing operations may result in unforeseen operating
difficulties and may require significant management attention and financial
resources that would otherwise be available for the ongoing development or
expansion of existing operations. Our ability to make future acquisitions may be
constrained by our ability to obtain additional financing.

     Acquisitions may involve a number of special risks, including:

     - unexpected losses of key employees, customers and suppliers of the
       acquired business;

     - conforming the financial, technological and management standards,
       processes, procedures and controls of the acquired business with those of
       our existing operations; and

     - increasing the scope, geographic diversity and complexity of our
       operations.

Possible future acquisitions could result in our incurring additional debt and
contingent liabilities, which could have a material adverse effect on our
financial condition and operating results.

  REPERCUSSIONS FROM TERRORIST ACTIVITIES OR ARMED CONFLICT COULD HARM OUR
  BUSINESS.

     Terrorist activities, anti-terrorist efforts and other armed conflict
involving the United States or its interests abroad may adversely affect the
United States and global economies and could prevent us from meeting our
financial and other obligations. If events of this nature occur and persist, the
attendant political instability and societal disruption could reduce overall
demand for oil and natural gas, potentially putting downward pressure on
prevailing oil and natural gas prices and causing a reduction in our revenues.
Natural gas and oil production facilities, transportation systems and storage
facilities could be direct targets of terrorist attacks, and our operations
could be adversely impacted if infrastructure integral to our operations is
destroyed or damaged by such an attack. Costs for insurance and other security
may increase as a result of these threats, and some insurance coverage may
become more difficult to obtain if available at all.

  OUR COMMODITY PRICE AND BASIS DIFFERENTIAL RISK MANAGEMENT ARRANGEMENTS MAY
  LIMIT OUR POTENTIAL GAINS.


     Commodity prices and basis differentials significantly affect our financial
condition, results of operations, cash flows and ability to borrow funds. Oil
and natural gas prices, as well as basis differentials, are affected by several
factors that we cannot control. We attempt to manage our exposure to oil and
natural gas price volatility by entering into commodity price risk management
arrangements for a portion of our expected production. In addition, we attempt
to manage our exposure to basis differentials between delivery points by
entering into basis swaps. In connection with the Acquisition, and as required
by our Revolving Credit Facility, we entered into a significant number of
hedging arrangements relating to the production from the Acquired Properties to
help us manage our exposure. Commodity price and basis differential risk
management transactions may limit our potential gains if oil and natural gas
prices were to rise substantially, or basis differentials were to fall
substantially, versus the price or basis differential established by the
arrangements. These transactions also expose us to credit risk of
non-performance by the counterparties to the transaction. In addition, our
commodity price and basis differential risk


                                        16
<PAGE>

management transactions may limit our ability to borrow under our Revolving
Credit Facility and may expose us to the risk of financial loss in certain
circumstances, including instances in which:

     - our production is less than expected;

     - there is a widening of price differentials between delivery points for
       our production and the delivery point assumed in non-basis hedge
       arrangements;

     - basis differentials tighten substantially from the prices established by
       these arrangements; or

     - the counterparties to our contracts fail to perform under terms of the
       contracts.


     In 2002, we experienced a $25.9 million loss attributable to our commodity
price risk management activities. No estimate of future settlements or
mark-to-market gains or losses is determinable as such amounts are contingent
upon commodity prices at the time of production. We may experience additional
losses from these activities in 2003. If commodity prices increase, our cash
settlement costs will also increase. In addition, certain of our commodity price
risk management arrangements will require us to deliver cash collateral or other
assurances of performance to the counterparties in the event that payment
obligations with respect to commodity price risk management transactions exceed
certain levels. As of February 28, 2003, we had $158.3 million of letters of
credit outstanding for this purpose.



     The table below shows the effect of a range of assumed prices on future
settlement of our commodity price risk management contracts outstanding as of
December 31, 2002:



 ESTIMATE OF FUTURE SETTLEMENT FOR OUTSTANDING COMMODITY PRICE RISK MANAGEMENT
                                 CONTRACTS (1)



<Table>
<Caption>
                                                        GAS
                                ---------------------------------------------------
                        OIL                  NORTHWEST                 CIG
                       ------           --------------------   --------------------
                       NYMEX    NYMEX   DIFFERENTIAL   PRICE   DIFFERENTIAL   PRICE   SETTLEMENTS (2)
                       ------   -----   ------------   -----   ------------   -----   ---------------
                                                                                      (IN THOUSANDS)
<S>                    <C>      <C>     <C>            <C>     <C>            <C>     <C>
PRICE DECK NO. 1.....  $30.00   $5.00      $1.60       $3.40      $1.75       $3.25      $(99,192)(3)
PRICE DECK NO. 2.....  $18.00   $3.00      $0.51       $2.49      $0.66       $2.34      $114,342(3)
</Table>


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


(1) All of our commodity price risk management contracts outstanding as of
    December 31, 2002 expire by December 31, 2005.



(2) Settlements were calculated based on the assumed high (Price Deck No. 1) and
    low (Price Deck No. 2) oil and natural gas prices on New York Mercantile
    Exchange, or NYMEX, Northwest Pipeline Rocky Mountain Index, or Northwest,
    and Colorado Interstate Gas Index, or CIG, that we believe were
    representative of market pricing assumptions as of December 31, 2002.



(3) Settlements were calculated based on the assumption that oil and natural gas
    prices will remain constant during the life of each contract.



  EXPLORATION IS A HIGH-RISK ACTIVITY. THE SEISMIC DATA AND OTHER ADVANCED
  TECHNOLOGIES WE USE ARE EXPENSIVE AND CANNOT ELIMINATE EXPLORATION RISKS,
  WHICH COULD CAUSE US TO LOSE ALL OR A PORTION OF OUR INVESTMENT IN ANY
  EXPLORATION ACTIVITY.



     Our oil and natural gas operations are subject to the economic risks
typically associated with drilling exploratory wells. In conducting exploration
activities, we may drill unsuccessful wells and experience losses and, if oil
and natural gas are discovered, we may be unable to economically produce or
satisfactorily market such oil and natural gas. The new wells we drill may fail
to be productive and we may be unable to recover all or any portion of our
investment. The presence of unanticipated pressure or irregularities in
formations, miscalculations or accidents may cause our exploration activities to
be unsuccessful, resulting in a total loss of our investment in such activities.
The cost of drilling, completing and operating wells is often uncertain. Our
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which may be beyond our control, including unexpected
drilling conditions, title problems, weather conditions, compliance with
environmental and other governmental requirements and shortages or delays in the
delivery of equipment and services.


                                        17
<PAGE>


     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.
Such data is not conclusive in determining 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.



  FAILURE TO REPLACE RESERVES MAY NEGATIVELY AFFECT OUR BUSINESS.



     Our future success depends upon our ability to find, develop or acquire
additional oil and natural gas reserves that are economically recoverable. Our
proved reserves generally decline when reserves are produced, unless we conduct
successful exploration or development activities or acquire properties
containing proved reserves, or both. We may not be able to find, develop or
acquire additional reserves on an economic basis. Furthermore, if oil and
natural gas prices increase, our finding costs for additional reserves could
also increase.



  RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN. ANY MATERIAL INACCURACIES IN OUR
  RESERVE ESTIMATES OR ASSUMPTIONS UNDERLYING OUR RESERVE ESTIMATES, 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 included or incorporated by reference in this prospectus represents
estimates based on reports prepared or audited by independent petroleum
engineers and prepared by our internal engineers. Reserve 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;



     - assumptions concerning future oil and natural gas prices, future
       operating costs and capital expenditures; and



     - estimates of future severance and excise taxes and workover and remedial
       costs.



     Estimates of reserves based on risk of recovery and estimates of expected
future net cash flows prepared or audited 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 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.



  MANY OF OUR COMPETITORS HAVE GREATER FINANCIAL, TECHNOLOGICAL AND OTHER
  RESOURCES THAN WE HAVE, WHICH COULD MAKE IT DIFFICULT FOR US TO EFFECTIVELY
  COMPETE WITH OTHER COMPANIES IN OUR INDUSTRY.



     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 major and 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;


                                        18
<PAGE>


     - integrating new technologies; and



     - acquiring the personnel, equipment and expertise necessary to develop and
       operate our properties.



     Many other companies have financial, technological and other resources
substantially greater than our own. These companies may be able to pay more for
exploratory prospects and productive oil and natural gas properties and may be
able to define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Further, many of our
competitors may enjoy technological advantages over us and may be able to
implement new technologies more rapidly than we can. Our ability to explore for
oil and natural gas 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 AND
  SAFETY REGULATIONS, THAT CAN ADVERSELY AFFECT THE COST, MANNER OR FEASIBILITY
  OF DOING BUSINESS.



     Our operations and facilities are subject to certain Federal, state and
local laws and regulations relating to the exploration for, and the development,
production and transportation of, oil and natural gas, as well as environmental
and safety matters. Future laws or regulations, any adverse change in the
interpretation of existing laws and regulations, or our failure to comply with
existing legal requirements may harm our business, results of operations and
financial condition. We may be required to make large and unanticipated capital
expenditures to comply with environmental and other governmental regulations,
such as:



     - land use restrictions;



     - drilling bonds and other financial responsibility requirements;



     - spacing of wells;



     - unitization and pooling of properties;



     - habitat and endangered species protection, reclamation and remediation,
       and other environmental protection;



     - safety precautions;



     - operational reporting; and



     - taxation.



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



     - personal injuries;



     - property and natural resource damages;



     - oil spills and releases or discharges of hazardous materials;



     - well reclamation costs;



     - remediation and clean-up costs and other governmental sanctions, such as
       fines and penalties; and



     - other environmental damages.



     Our operations could be significantly delayed or curtailed and our costs of
operations could significantly increase as a result of regulatory requirements
or restrictions. We are unable to predict the ultimate cost of compliance with
these requirements or their effect on our operations.


                                        19
<PAGE>


  WE CANNOT CONTROL ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND MAY HAVE
  LIMITED ABILITY TO INFLUENCE OPERATIONS ON SUCH PROPERTIES TO CONTROL
  ASSOCIATED COSTS.



     Other companies operate approximately 23% of the net present value of our
reserves and 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 will be outside 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.



 INABILITY OR UNWILLINGNESS TO FUND OUR CAPITAL EXPENDITURES MAY RESULT IN
 REDUCTION OR FORFEITURE OF OUR INTERESTS IN SOME OF OUR NON-OPERATED PROJECTS.



     Where we are not the majority owner or operator of a particular oil and
natural gas project, we may have no control over the timing or amount of capital
expenditures associated with such project. If we are unable or unwilling to fund
our capital expenditures relating to such projects when required by the majority
owner or operator, our interests in these projects may be reduced or forfeited.



  OUR BUSINESS INVOLVES MANY OPERATING RISKS THAT 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;



     - 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 operations; and



     - repair and remediation costs.


                                        20
<PAGE>


     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.



  WE ARE VULNERABLE TO RISKS ASSOCIATED WITH OPERATING IN THE GULF OF MEXICO
  THAT COULD NEGATIVELY IMPACT OUR OPERATIONS AND FINANCIAL RESULTS.



     Our operations and financial results could be significantly impacted by
conditions in the Gulf of Mexico because we explore and produce extensively in
that area. As a result of this activity, we are vulnerable 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;



     - remediation and other costs resulting from oil spills or releases of
       hazardous materials; and



     - failure of equipment or facilities.



     For example, in 2002, adverse weather conditions caused us to temporarily
shut-in our offshore operations and reduce production, which resulted in a
decline in production by approximately 0.9 Bcf.



     In addition, we intend to conduct some of our exploration in the deep
waters (greater than approximately 1,000 feet) 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 oilfield service
infrastructure present in its shallower waters. As a result, deep water
operations may require a significant amount of time between a discovery and the
time that we can market our production, 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
may be greater there than for our operations elsewhere. Also, our revenues and
return on capital will depend significantly on prices prevailing during these
relatively short production periods.



  THE LOSS OF KEY MEMBERS OF OUR MANAGEMENT TEAM, OR DIFFICULTY ATTRACTING AND
  RETAINING EXPERIENCED TECHNICAL PERSONNEL, COULD REDUCE OUR COMPETITIVENESS
  AND PROSPECTS FOR FUTURE SUCCESS.



     The successful implementation of our strategies and handling of other
issues integral to our future success will depend, in part, on our experienced
management team. The loss of key members of our management team, including
Donald D. Wolf, our Chairman and Chief Executive Officer, and Barth E. Whitham,
our President and Chief Operating Officer, could have an adverse effect on our
business. We entered into employment agreements with Messrs. Wolf and Whitham to
secure their employment with the Company. We do not carry key man insurance. Our
exploratory drilling success and the success of other activities integral to our
operations will depend, in part, on our ability to attract and retain
experienced explorationists, engineers and other professionals. Competition for
experienced explorationists, engineers and some other professionals is extremely
intense. If we cannot retain our technical personnel or attract additional
experienced technical personnel, our ability to compete could be harmed.



  THE MARKETABILITY OF OUR PRODUCTION MAY BE NEGATIVELY AFFECTED BY FACTORS OVER
  WHICH WE MAY HAVE NO CONTROL, INCLUDING GENERAL ECONOMIC CONDITIONS AND
  FEDERAL AND STATE REGULATIONS AND POLICIES.



     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


                                        21
<PAGE>


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.



  OUR PRINCIPAL STOCKHOLDERS OWN A SIGNIFICANT AMOUNT OF OUR COMMON STOCK, WHICH
  MAY GIVE THEM A CONTROLLING INFLUENCE OVER CORPORATE TRANSACTIONS AND MAY
  DELAY OR PREVENT A CHANGE IN OUR MANAGEMENT OR VOTING CONTROL.



     Our principal stockholders include Medicor Foundation, also referred to as
Medicor, Westport Energy LLC, also referred to as WELLC and, together with
Medicor, as the Medicor Group, ERI Investments, Inc., an affiliate of Equitable
Resources Inc., also referred to as ERI, and a group of former stockholders of
Belco Oil & Gas Corp., also referred to as the Belfer Group. The Medicor Group,
ERI and the Belfer Group beneficially owned approximately 21.3%, 20.8% and
11.1%, respectively, of our outstanding common stock as of December 31, 2002,
which collectively represented approximately 53.2% of our outstanding common
stock as of that date. These stockholders, acting together through a
shareholders agreement, based on their share ownership, were able to control the
outcome of the election of directors as well as, if they choose to act together,
the adoption or amendment of provisions in our articles of incorporation or
bylaws and the approval of mergers and other significant corporate transactions.
On October 1, 2003, these stockholders entered into a termination and voting
agreement, terminating the shareholders agreement and providing for certain
voting arrangements with respect to the election of directors at the 2004 annual
meeting of our stockholders. Although the voting provisions of the termination
and voting agreement are limited solely to the 2004 annual meeting of our
stockholders, based on their share ownership as of December 31, 2003, in the
aggregate representing approximately 43.3% of our outstanding common stock as of
that date, EQT Investments, Inc., a successor to ERI, Medicor, WELLC and the
Belfer Group may be able to influence or control the outcome of any subsequent
elections of directors, amendments of our articles of incorporation or bylaws or
any other significant corporate transactions, if they choose to act together.
These factors may also delay or prevent a change in our management or voting
control.



  OUR OIL AND GAS MARKETING ACTIVITIES MAY EXPOSE US TO CLAIMS FROM ROYALTY
  OWNERS.



     In addition to marketing our oil and gas production, our marketing
activities generally include marketing oil and gas production for royalty
owners. Recently, royalty owners have commenced litigation against a number of
companies in the oil and gas production business claiming that amounts paid for
production attributable to the royalty owners' interest violated the terms of
the applicable leases and laws in various respects, including the value of
production sold, permissibility of deductions taken and accuracy of quantities
measured. Some of this litigation was commenced as class action suits, including
two class action suits filed against Westport involving some of our Wyoming
properties, and we may be required to make payments as a result of such
litigation. In addition, our costs relating to the marketing of oil and gas may
increase as new cases are decided and the law in this area continues to develop.


                                        22
<PAGE>

                     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 report:

          ASP FLOOD.  A tertiary recovery technique that includes injection of a
     mixture of chemicals into the producing reservoir designed to aid in the
     efficiency of producing the oil in place, thus increasing ultimate produced
     reserves.

          BASIS DIFFERENTIAL.  The difference between oil and natural gas prices
     quoted on the NYMEX and the prices we receive at the locations we deliver
     our produced oil and natural gas.

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

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

          BCF.  One billion cubic feet of natural gas at standard atmospheric
     conditions.

          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.

          CO(2) FLOOD OR INJECTIONS.  A tertiary recovery method in which CO(2)
     is injected into the reservoir to enhance oil recovery.

          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 the proved area of an oil or
     gas reservoir to the depth of a strategic horizon known to be productive.

          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 to find and produce oil or gas in an
     unproved area, to find a new reservoir in a field previously found to be
     productive at oil or gas in another reservoir, or to extend a known
     reservoir.

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

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

          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.

                                        23
<PAGE>

          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.

          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.

          MMBTU/D.  One million British thermal units per day.

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

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

          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.  Crude oil or condensate.

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

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

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

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

          PROVED RESERVES.  The estimated quantities of crude oil, natural gas
     and natural gas liquids which geological and engineering data demonstrate
     with reasonable certainty to be recoverable in future

                                        24
<PAGE>

     years from known reservoirs under existing economic and operating
     conditions, i.e., prices and costs as of the date the estimate is made, as
     such reserves are further defined in Rule 4-10(a)(2).

          PROVED UNDEVELOPED RESERVES.  Proved reserves that are expected to be
     recovered from new wells on undrilled acreage or from existing wells where
     a relatively major expenditure is required for recompletion.

          RESERVOIR.  A porous and permeable underground formation containing a
     natural accumulation of producible oil or gas that is confined by
     impermeable rock or water barriers and is individual and separate from
     other reservoirs.

          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.

          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.

          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.

          UNDEVELOPED ACREAGE.  Acreage held under lease, permit, contract or
     option that is not in a spacing unit for a producing well.

          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.

ITEM 2.  PROPERTIES

PROPERTIES -- PRINCIPAL AREAS OF OPERATIONS

     Our operations are concentrated in the following divisions: Northern, which
primarily includes properties in the Rocky Mountains, principally in North
Dakota and Wyoming; Western, which includes the Acquired Properties in the Uinta
Basin, Utah; Southern, which includes properties principally in Oklahoma, Texas
and Louisiana; and Gulf of Mexico, which includes our offshore properties. We
operate approximately 77% 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 Revolving Credit Facility and other
financing activities. Set forth below is summary information concerning average

                                        25
<PAGE>

daily production during the fourth quarter of 2002 and estimated reserves and a
pre-tax SEC net present value of estimated proved reserves discounted at 10%, as
of December 31, 2002 in our divisions.

<Table>
<Caption>
                                                                     AT DECEMBER 31, 2002
                                           ------------------------------------------------------------------------
                                                                                                NET PRESENT VALUE
                         QUARTER ENDED                 PROVED RESERVE QUANTITIES                  BEFORE INCOME
                       DECEMBER 31, 2002   -------------------------------------------------         TAXES(2)
                       AVERAGE NET DAILY                                                       --------------------
                          PRODUCTION                                 NATURAL GAS
                       -----------------   CRUDE OIL   NATURAL GAS     LIQUIDS       TOTAL       AMOUNT
DIVISION               MMCFE/D   PERCENT    (MMBBL)       (BCF)        (MMBBL)     (BCFE)(1)   (MILLIONS)   PERCENT
--------               -------   -------   ---------   -----------   -----------   ---------   ----------   -------
<S>                    <C>       <C>       <C>         <C>           <C>           <C>         <C>          <C>
Northern.............   107.3      28.5%     34.3          146.9          --          352.9     $  514.9      21.4%
Western(3)...........    11.1       2.9%      1.2          589.3          --          596.1        554.7      23.1%
Southern.............   150.6      40.0%     36.7          255.4          --          475.6        876.9      36.4%
Gulf of Mexico.......   107.5      28.6%      7.0          109.8         0.5          155.0        459.3      19.1%
                        -----     -----      ----        -------         ---        -------     --------     -----
     Total...........   376.5     100.0%     79.2        1,101.4         0.5        1,579.6     $2,405.8     100.0%
                        =====     =====      ====        =======         ===        =======     ========     =====
</Table>

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

(1) Mmbbls converted to Bcfe at a six to one conversion.

(2) Excludes value attributable to the gathering and compression assets of
    Westport Field Services, LLC, one of our subsidiaries.

(3) Includes production from the Acquisition closing date of December 17, 2002
    through December 31, 2002.

  NORTHERN DIVISION

     The Northern Division conducts operations in the Rocky Mountain region
which includes the Williston, Powder River, Big Horn, Wind River and Green River
Basins. The division represented approximately 21% of our net present value of
estimated proved reserves as of December 31, 2002, and contributed approximately
28% of our fourth quarter 2002 net production. We have interests in 563,695
developed and 1,145,920 undeveloped gross acres in the division and in 2,111
gross (approximately 805 net) producing wells in this division.

     Our strategy in the Northern Division is to exploit lower-risk infill,
horizontal and secondary/tertiary recovery opportunities on existing properties,
pursue gas-weighted exploration opportunities and make tactical acquisitions to
enhance current operations.

     On March 1, 2002, we completed the purchase of producing oil and gas
properties located in the Williston Basin in North Dakota and Montana for
approximately $39 million. The total acquired proved reserves were approximately
43 Bcfe, of which approximately 90% is oil. We operate over 70% of these
properties. Our net production from these properties for the fourth quarter 2002
was approximately 1,550 bbl/d.

     Williston Basin.  Our activity in the Williston Basin continues to focus on
horizontal field extensions, field deepenings to new horizons and growth of our
secondary recovery projects. Our most active project continues to be the Wiley
field. We operate this waterflood with a 54% working interest. In 2000, we
initiated a horizontal drilling program and through December 31, 2002 have
drilled 37 wells, all of which were successful. In addition to the horizontal
drilling, we increased water injection capacity to expand our waterflood
program. As a result of this activity, gross daily production has increased from
approximately 600 bbl/d in April 2000 to over 3,000 bbl/d at the end of the
fourth quarter 2002. Over the next 12 months, we plan to drill 10 to 15
additional wells in the Wiley field while continuing to increase water injection
capacity. Additionally, we plan to drill horizontal development wells in our
Horse Creek, TR and Bear Creek fields.

     Greater Green River Basin.  In the Greater Green River Basin we have
interests in over 400,000 gross undeveloped acres. Over the next 12 to 24 months
we expect to drill seven to 10 exploration wells. One of the primary operating
areas within the basin is the Moxa Arch Complex. Production from Moxa Arch wells
tends to be long-lived, with the potential for greater than a 25 year reserve
life. In the

                                        26
<PAGE>

Moxa Arch and Wamsutter areas of southwest Wyoming, we plan to drill 10 to 15
development wells over the next 12 months.

     Powder River Basin.  In the Powder River Basin, we currently have interests
in approximately 50,000 gross acres, which we believe are prospective for
coalbed methane drilling. From the beginning of 2000 through December 31, 2002,
we participated in the drilling of 273 coalbed methane wells, 270 of which were
successful. We operate 145 of these wells. In 2003, we expect to continue
coalbed methane drilling in both the Wyodak and Big George coal-bearing areas of
the Powder River Basin.

     Big Horn Basin.  The Gooseberry field is our most significant property in
the Big Horn Basin. We own a 100% working interest (nearly 90% net revenue
interest) in this field, which consists of two waterflood units. Since acquiring
the field in February 1995, we have more than doubled the production from
approximately 535 bbl/d to over 1,100 bbl/d in December 2002. In 2002, a larger
pipeline was placed in service to accommodate the increasing production from the
unit. During the next 12 months, we plan to drill three to four additional
development wells and to expand water injection capacity. We currently have
interests in over 200,000 gross undeveloped acres in the Big Horn Basin.

  WESTERN DIVISION

     On December 17, 2002, we closed the acquisition of producing properties,
undeveloped leasehold, gathering and compression facilities and other related
assets in the Greater Natural Buttes area of Uintah County, Utah for
approximately $507 million. This division represented approximately 23% of our
net present value of estimated proved reserves as of December 31, 2002 and was
producing approximately 68 Mmcfe/d on December 31, 2002. We have interests in
212,880 developed and 53,120 undeveloped gross acres and in 971 gross
(approximately 755 net) producing wells in this division.

     In addition to establishing a new core area, the Acquisition:

     - increases our proved reserves by approximately 60%, or 596 Bcfe,
       replacing approximately 459% of our 2002 production and giving us nearly
       1 Tcfe of proved reserves in the Rocky Mountains;

     - raises pro forma production approximately 19%, to approximately 434
       Mmcfe/d, placing us among the 20 largest domestic independent exploration
       and production companies, based on fourth quarter 2002 daily production;

     - adds long-life, operated gas properties with a reserve to production
       ratio of over 20 years, extending our overall reserve life index from
       approximately 7 years to approximately 10 years and increasing the gas
       portion of both our proved reserves and production to approximately 70%;

     - contains upside potential, with over 600 proved undeveloped locations;

     - provides exploitation and exploration opportunities on 244,000 net acres
       of leasehold, including targets outside the producing areas and deeper
       formations within the producing areas; and

     - allows us to control the gathering and marketing of our natural gas and
       affords us access to interstate pipelines flowing east, such as Colorado
       Interstate Gas, and west, such as Questar Pipeline.

     Natural gas was first discovered in the Greater Natural Buttes field in
1955. Since that time, more than 900 Bcf of natural gas has been produced. Since
1991, development accelerated with more than 1,000 wells drilled in the field,
approximately 98% of which were successful. The properties are characterized by
established production profiles and long reserve lives. Producing horizons range
from 5,000 to 14,000 feet, with production coming primarily from the Wasatch and
Upper Mesa Verde formations.

     The Natural Buttes Unit has undergone a series of downspacings from the
original spacing of 320 acres per well to current spacing of 40 acres per well.
In adjacent units, operators are currently proposing downspacing to 20 acres per
well. Operators of adjacent units have also drilled successful gas

                                        27
<PAGE>

wells to the Lower Mesa Verde and Mancos formations underlying the primary field
production, which could be prospective on a portion of our acreage.

     In the Greater Natural Buttes area, we operate approximately 650 net
producing wells, or approximately 88% of the net present value of our proved
reserves in the area. Through our high working interest and level of operations
we can control the majority of drilling, completion and production of wells. We
expect to drill 80 to 90 wells in 2003 and plan to expand the program to 120 to
150 wells per year for the next three to four years thereafter.

  SOUTHERN DIVISION

     The Southern Division conducts operations in the Permian Basin, onshore
Gulf Coast and Mid-Continent regions. This division represented 36% of the net
present value of our estimated proved reserves as of December 31, 2002, and
contributed 40% of our fourth quarter 2002 net production. We have interests in
540,429 developed and 88,196 undeveloped gross acres and in 3,393 gross
(approximately 1,368 net) producing wells in this division.

     Permian Basin.  Our principal activity in the Permian Basin continues to be
focused on development of the Andrews unit and the Shafter Lake San Andres unit
waterfloods.

     - Andrews Unit.  The Andrews unit waterflood produces from the
       Wolfcamp/Penn formation at approximately 8,600 feet. We have a 98.6%
       working interest in this 3,230-acre unit. During 2002 we continued
       expanding the waterflood program by drilling additional wells, converting
       wells to injectors and performing workovers on existing wells. As a
       result, production continues to increase from an 855 bbl/d average in
       2000 to over 1,200 bbl/d as of December 31, 2002. We believe that
       production from this waterflood unit can be further enhanced with the use
       of CO(2) flooding or other tertiary recovery methods.

     - Shafter Lake San Andres Unit.  The Shafter Lake San Andres unit is a
       12,880-acre unit that produces from the Grayburg and San Andres
       formations at a depth of approximately 4,500 feet. We have an 81.4%
       working interest in this secondary recovery unit. In 2002, we drilled
       eight wells on 10-acre spacing and plan to drill 10 to 15 additional
       10-acre wells in 2003. The unit was producing 655 bbl/d as of December
       31, 2002. Operators of nearby San Andres fields have successfully drilled
       to 10-acre spacing before CO(2) injection. We believe the potential
       exists for CO(2) flooding as the field matures.

     Onshore Gulf Coast.  Our Gulf Coast operations are primarily focused in the
Yegua trend of southeast Texas, and in Northern Louisiana where we are active in
two fields, the Elm Grove field and the North Louisiana field complex.

     - Southeast Texas Properties.  We acquired these oil and gas properties on
       September 30, 2002. The total estimated proved reserves were
       approximately 67 Bcfe, of which 82% is natural gas. We operate
       essentially all of these properties. We also acquired approximately
       10,000 net undeveloped acres and an interest in 120 square miles of 3-D
       seismic data. Since closing, we have participated in two shoots for an
       additional 185 square miles of 3-D seismic data, increased net production
       from approximately 28 Mmcfe/d to 35 Mmcfe/d and drilled two successful
       development wells and two exploration wells, of which one was successful.
       Currently, we have two rigs drilling in the area and expect to drill 15
       exploration prospects over the next 12 to 24 months.

     - Elm Grove Field.  We maintained an active development drilling program in
       the Elm Grove field in 2002 by drilling 24 wells, all of which were
       successful. In 2003 we expect to drill 20 to 25 wells. Net production has
       continued to grow throughout the year to average approximately 17.4
       Mmcfe/d in fourth quarter 2002.

     - North Louisiana Field Complex.  Development drilling in this four field
       complex continues to be active. In 2002 we drilled 16 wells, 15 of which
       were successful. Net production fourth quarter

                                        28
<PAGE>

       2002 averaged 9.6 Mmcfe/d. We anticipate drilling between 15 and 25 wells
       in this region in each of the next two years.

     Mid-Continent.  Our Mid-Continent operations are currently focused in
Oklahoma and Kansas. Oil production is concentrated in our operated waterfloods
in Oklahoma, while natural gas production is primarily from third party operated
wells in Oklahoma and in our operated wells in Kansas.

  GULF OF MEXICO DIVISION

     The Gulf of Mexico Division represented 19% of the net present value of our
estimated proved reserves as of December 31, 2002, and contributed 29% of our
fourth quarter 2002 net production. As of December 31, 2002, we have interests
in 318,469 developed and 312,245 undeveloped gross acres in the Gulf of Mexico
and in 140 gross (approximately 39 net) producing wells.

     In addition to a production base with numerous exploitation opportunities
within our developed acreage, the Gulf of Mexico provides us with moderate-risk
exploration targets. We drilled 16 exploration wells in the Gulf of Mexico in
2001, 11 of which were successful, and 12 exploration wells 2002, 3 of which
were successful. We have under license 3-D seismic data covering approximately
19,500 square miles (approximately 2,500 blocks) and 2-D seismic data covering
150,000 linear miles within the Gulf of Mexico.

     West Cameron Blocks 180/198.  The West Cameron Blocks 180/198 complex is
located 30 miles offshore in 52 feet of water. In 2002, we drilled 2 development
wells, 1 of which was successful. Several recompletions were also done in 2002.
The complex has produced approximately 1.7 Tcf of natural gas and 10 Mmbbl of
oil from over 20 separate producing zones since its discovery. In fourth quarter
2002, the field produced 36.1 Mmcfe/d net to our interest.

     High Island Block 197.  This field is located approximately 28 miles
offshore in 50 feet of water and was discovered in the third quarter of 2001. We
have a 25% non-operated working interest in the field. Four additional wells
have been drilled, three of which were successful. The field commenced
production in May 2002, from one well. In fourth quarter 2002 the field averaged
17.9 Mmcfe/d net to our interest.

     High Island Block 84.  This field is located approximately 23 miles
offshore in 50 feet of water and was discovered in the third quarter of 2001,
with three development wells being drilled in 2002. We operate the field.
Production commenced in June 2002 from two wells. We expect the two remaining
wells to commence production in 2003. In fourth quarter 2002 the field averaged
8.3 Mmcfe/d net to our interest.

     South Timbalier Block 316.  We discovered this field located approximately
66 miles offshore in 400 feet of water in the fourth quarter of 2001. We operate
the field with a 40% working interest. Three wells have been drilled in the
field. We expect to install a platform and commence production in the second
half of 2003. Facility capacity on the platform will be 150 Mmcfe/d (47 Mmcfe/d
net).

     Galveston Block 352.  We drilled a successful exploratory well in the
spring of 2002 and put the well on production in August. We operate the well
with a 67% working interest. In fourth quarter 2002 it averaged 2.2 Mmcfe/d net
to our interest.

     Green Canyon Block 640.  We have a 3.5% overriding royalty interest in the
Green Canyon Block 640, covering part of a 2002 discovery drilled by
ChevronTexaco. Delineation drilling and evaluation within the field called
Tahiti is ongoing.

                                        29
<PAGE>

PROVED RESERVES

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

<Table>
<Caption>
                                                          AS OF DECEMBER 31,
                                                --------------------------------------
                                                   2002          2001          2000
                                                ----------     --------     ----------
<S>                                             <C>            <C>          <C>
OIL (MBBLS)
  Developed...................................      60,576       51,068         28,673
  Undeveloped.................................      18,593       17,588          6,127
                                                ----------     --------     ----------
     Total....................................      79,169       68,656         34,800
                                                ==========     ========     ==========
NATURAL GAS (MMCF)
  Developed...................................     676,365      401,106        183,872
  Undeveloped.................................     425,018      115,050         58,839
                                                ----------     --------     ----------
     Total....................................   1,101,383      516,156        242,711
                                                ==========     ========     ==========
NATURAL GAS LIQUIDS (MBBLS)
  Developed...................................         378          119            247
  Undeveloped.................................         154          199            212
                                                ----------     --------     ----------
     Total....................................         532          318            459
                                                ==========     ========     ==========
TOTAL (MMCFE).................................   1,579,589      930,000        454,265
                                                ==========     ========     ==========
PRESENT VALUE ($ IN THOUSANDS)
  Developed...................................  $1,744,795     $737,625     $1,234,605
  Undeveloped.................................     661,023      186,718        336,287
                                                ----------     --------     ----------
     Total....................................  $2,405,818(1)  $924,343(2)  $1,570,892
                                                ==========     ========     ==========
STANDARDIZED MEASURE ($ IN THOUSANDS)(3)......  $1,766,451     $747,029     $1,098,399
                                                ==========     ========     ==========
</Table>

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

(1) The difference in net present value from December 31, 2001 to December 31,
    2002 resulted almost entirely from (i) the addition of 722.7 Bcfe of proved
    reserves acquired in connection with the Williston Basin, Southeast Texas
    and Utah acquisitions, (ii) the addition of 58 Bcfe as discoveries and
    extensions and (iii) the increase in commodity prices used to determine net
    present value (from $19.78 to $31.23 per bbl of oil and from $2.72 to $4.58
    per Mmbtu of natural gas).

(2) The difference in net present value from December 31, 2000 to December 31,
    2001 resulted almost entirely from (i) the addition of 502.7 Bcfe of proved
    reserves acquired in connection with the merger between Westport Resources
    Corporation and Belco Oil & Gas Corp., (ii) the addition of 92 Bcfe as
    discoveries and extensions, (iii) the downward revision of 33 Bcfe due to
    revisions of previous estimates and (iv) the decrease in commodity prices
    used to determine net present value (from $26.83 to $19.78 per bbl of oil
    and from $9.52 to $2.72 per Mmbtu of natural gas).

(3) 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 our oil and gas reserves and the net present value
of such reserves as of December 31, 2002 are based upon reserve reports prepared
by Ryder Scott Company, L.P. and our engineering staff. Ryder Scott reports
covered 81% of the total net present value of estimates of total proved
reserves, evaluating 58% and auditing 23%. The internally generated report
covered the remaining 19% of the net present value. At December 31, 2001 Ryder
Scott audited 87% of the total net present value of estimates of total proved
reserves and the remaining 13% of net present value of the reserves was
unaudited. Estimates of total proved reserves at December 31, 2000 were prepared
by Ryder Scott and

                                        30
<PAGE>

Netherland, Sewell and Associates, Inc. and our engineering staff. The Ryder
Scott and Netherland Sewell reports covered approximately 85% of the total net
present value of our reserves and the internally generated report covered the
remaining 15% of the net present value for 2000.

     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. 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 of
each of the periods indicated:


<Table>
<Caption>
                                                           YEAR ENDED DECEMBER 31,
                                                         ----------------------------
                                                           2002      2001      2000
                                                         --------   -------   -------
<S>                                                      <C>        <C>       <C>
PRODUCTION DATA (1):
Oil (Mbbls)............................................     7,927     4,929     3,584
Natural Gas (Mmcf).....................................    81,787    58,430    34,072
NGL (Mbbls)............................................        93        22        41
Total Mmcfe............................................   129,908    88,136    55,822
AVERAGE PRICES:
Oil (per Bbl)..........................................  $  23.60   $ 21.79   $ 23.39
Natural Gas (per Mcf)..................................      2.92      3.62      3.97
NGL (per Bbl)..........................................     16.00     18.97     21.02
Total (per Mcfe).......................................      3.29      3.62      3.94
Hedging effect (per Bbl)...............................      (.06)      .10     (4.59)
Hedging effect (per Mcf)...............................      (.01)      .03      (.24)
Hedging effect (per Mcfe)..............................      (.01)      .02      (.44)
</Table>


                                        31
<PAGE>


<Table>
<Caption>
                                                           YEAR ENDED DECEMBER 31,
                                                         ----------------------------
                                                           2002      2001      2000
                                                         --------   -------   -------
<S>                                                      <C>        <C>       <C>
AVERAGE COSTS (PER MCFE):
Lease operating expense................................  $    .69   $   .63   $   .62
Production taxes.......................................       .18       .15       .19
Transportation costs...................................       .06       .06       .05
General and administrative.............................       .18       .20       .14
Depletion, depreciation and amortization...............      1.56      1.41      1.16
</Table>


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

(1) Production and price history of the Western Division consisting of the
    Acquired Properties are included only for the period from December 17, 2002,
    the acquisition date, to December 31, 2002.

PRODUCING WELLS

     The following table sets forth information at December 31, 2002 relating to
the producing wells in which we owned a working interest as of that date. We
also held royalty interests in 1,865 producing wells as of that date. Wells are
classified as oil or natural gas wells according to their predominant production
stream.

<Table>
<Caption>
                                            GROSS PRODUCING   NET PRODUCING   AVERAGE WORKING
                                                 WELLS            WELLS          INTEREST
                                            ---------------   -------------   ---------------
<S>                                         <C>               <C>             <C>
Crude oil and liquids.....................       3,061            1,414            46.2%
Natural gas...............................       3,554            1,553            43.7%
                                                 -----            -----
  Total...................................       6,615            2,967              --
                                                 =====            =====
</Table>

ACREAGE

     The following table sets forth information at December 31, 2002 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. The term "gross acres"
refers to the total number of acres in which we own a working interest. The term
"net acres" refers to gross acres multiplied by our fractional working interest
therein.

<Table>
<Caption>
                                                              GROSS ACREAGE   NET ACREAGE
                                                              -------------   -----------
<S>                                                           <C>             <C>
DEVELOPED:
  Northern..................................................      563,695        241,059
  Western...................................................      212,880        192,070
  Southern..................................................      540,429        250,093
  Gulf of Mexico............................................      318,469         80,339
                                                                ---------      ---------
  Total Developed...........................................    1,635,473        763,561
UNDEVELOPED:
  Northern..................................................    1,145,920        497,908
  Western...................................................       53,120         51,930
  Southern..................................................       88,196         41,452
  Gulf of Mexico............................................      312,245        189,276
                                                                ---------      ---------
  Total Undeveloped.........................................    1,599,481        780,566
                                                                ---------      ---------
     Total..................................................    3,234,954      1,544,127
                                                                =========      =========
</Table>

     The total net acres expiring in 2003, 2004 and 2005 are 114,946, 148,375
and 173,799, respectively.

                                        32
<PAGE>

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>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2002     2001     2000
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
DEVELOPMENT WELLS:
  Productive
     Gross..................................................  194.0    242.0    169.0
     Net....................................................   96.0     86.0     40.0
  Dry
     Gross..................................................    6.0      9.0      8.0
     Net....................................................    3.7      3.4      1.7
EXPLORATORY WELLS:
  Productive
     Gross..................................................    6.0     18.0     12.0
     Net....................................................    2.4      5.9      5.8
  Dry
     Gross..................................................   13.0      6.0      8.0
     Net....................................................    5.5      3.3      3.4
</Table>

     As of December 31, 2002, 6 additional exploration and eleven development
wells were in progress.

ITEM 3.  LEGAL PROCEEDINGS

     Westport Oil and Gas Company, L.P., our wholly-owned subsidiary, is a
defendant in a case brought in July 2001 against its predecessor, Belco Energy
Corp., in the district court of Sweetwater County, Wyoming. The complaint seeks
damages on behalf of a purported class of royalty owners for alleged improper
deduction, valuation and reporting under the Wyoming Royalty Payment Act in
connection with royalty payments made by Belco on production from wells it
operates in the Moxa Arch area of the Green River Basin. Plaintiffs have advised
us that they calculate the amount of damages allegedly owed by Belco to be
approximately $1,165,000, which includes attorneys fees and litigation costs. We
have denied liability for any of these damages and believe that we have valid
defenses to plaintiffs' claims. Class certification and discovery have been
stayed pending the decision by the Wyoming Supreme Court in a case involving
unrelated parties that may have a bearing on this case and other similar cases
filed by plaintiffs against other oil and gas industry operators in the Green
River Basin. Settlement discussions have occurred with plaintiffs and are
ongoing. We believe that our potential liability with respect to this proceeding
is not material in the aggregate to our financial position, results of
operations or cash flows. Accordingly, we have not established a reserve for
loss in connection with this proceeding.

     From time to time, we may be a party to various other legal proceedings.
Except as discussed herein, we are not currently party to any material pending
legal proceedings.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matters were submitted during the fourth quarter of the fiscal year
covered by this Form 10-K to a vote of our security holders, through the
solicitation of proxies or otherwise.

                                        33
<PAGE>

                                    PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

PRICE RANGE OF COMMON STOCK

     Our common stock is listed and traded on the New York Stock Exchange, or
NYSE, under the symbol "WRC." Prior to our merger with and into Belco, Belco
common stock was listed and traded on the NYSE under the symbol "BOG." The
following table sets forth the high and low sales prices per share of Belco and
Westport common stock on the NYSE, for the periods indicated:

<Table>
<Caption>
                                                         BELCO             WESTPORT
                                                    COMMON STOCK(1)    COMMON STOCK(2)
                                                    ---------------    ----------------
                                                     HIGH      LOW      HIGH      LOW
                                                    ------    -----    ------    ------
<S>                                                 <C>       <C>      <C>       <C>
2000
First Quarter.....................................  $11.25    $5.31    $   --    $   --
Second Quarter....................................   10.50     7.38        --        --
Third Quarter.....................................    9.63     8.00        --        --
Fourth Quarter....................................   12.44     8.50        --        --
2001
First Quarter.....................................  $12.75    $8.40    $   --    $   --
Second Quarter....................................   10.60     7.90        --        --
Third Quarter (through August 20, 2001)...........    9.15     8.20        --        --
Third Quarter (from August 21, 2001)..............      --       --     20.39     12.60
Fourth Quarter....................................      --       --     17.94     13.90
2002
First Quarter.....................................  $   --    $  --    $19.77    $15.44
Second Quarter....................................      --       --     21.18     15.40
Third Quarter.....................................      --       --     18.69     13.20
Fourth Quarter....................................      --       --     21.40     16.20
</Table>

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

(1) Stock price information for periods prior to August 21, 2001, the effective
    date of the merger with Belco, are for shares of Belco common stock listed
    and traded on the NYSE under the symbol "BOG." August 20, 2001 was the last
    full trading day on which shares of Belco common stock were traded prior to
    the merger with Belco.

(2) The merger with Belco became effective on August 21, 2001. In accordance
    with the agreement governing the merger with Belco, each outstanding share
    of Belco common stock was exchanged for 0.4125 of a share of Westport common
    stock.

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 on our common stock in the foreseeable future. Payment of any future
dividends on our common stock 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. The declaration and payment of any future dividends is currently
prohibited by our Revolving Credit Facility and may be similarly restricted in
the future.

                                        34
<PAGE>

RECENT SALES OF UNREGISTERED SECURITIES

     On November 19, 2002, we completed the private equity offering of 3.125
million shares of our common stock to Spindrift Partners, L.P., Spindrift
Investors (Bermuda) L.P., Global Natural Resources III and Global Natural
Resources III L.P. at a net price to us of $16.00 per share for aggregate
proceeds of $50 million. The purchasers may be prohibited from selling this
common stock at our option for up to 187 days in the event we pursue a public
equity offering during the next two years. The terms of the sale were negotiated
on November 11, 2002 and the net price represents a 9% discount from the closing
price of our common stock on the New York Stock Exchange as of that date.

     In connection with the private equity offering, we agreed to file a shelf
registration statement registering the resale by the selling stockholders from
time to time of the common stock we issued in the private equity offering. We
also agreed to use our reasonable best efforts to cause the registration
statement to become effective within 90 days of the closing of the private
equity offering. In addition, we agreed, subject to certain rights of
suspension, to keep such registration statement effective until the earlier of
(1) the date on which all of the shares have been (a) sold under the
registration statement or (b) distributed pursuant to Rule 144(k) under the
Securities Act or (2) two years after the date of the stock purchase agreement.
On December 31, 2002, we filed the shelf registration statement registering the
resale by the selling stockholders from time to time of our common stock issued
in the private equity offering, which registration statement was declared
effective by the SEC on January 7, 2003.

ITEM 6.  SELECTED FINANCIAL DATA

     The following table sets forth selected consolidated financial data for
Westport as of the dates and for the periods indicated. The financial data for
the five years ended December 31, 2002 were derived from our Consolidated
Financial Statements. Future results may differ substantially from historical
results because of changes in oil and natural gas prices, increases or decreases
in production or other factors, many of which are beyond our control. The
following data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations," which includes a
discussion of factors materially affecting the comparability of the information
presented, and our financial statements and the notes thereto included elsewhere
in this report.


<Table>
<Caption>
                                                       YEAR ENDED DECEMBER 31, 2000
                                     ----------------------------------------------------------------
                                        2002          2001          2000          1999        1998
                                     ----------   ------------   -----------   ----------   ---------
                                                   (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                  <C>          <C>            <C>           <C>          <C>
STATEMENTS OF OPERATIONS DATA:
Operating revenues:
  Oil and natural gas sales........  $  428,430    $  317,278     $ 244,669     $ 83,393    $  52,057
  Hedge settlements................      (1,276)        2,091       (24,627)      (7,905)         298
  Commodity price risk management
     activities:
     Non-hedge settlements.........         822        15,300            --           --           --
     Non-hedge change in fair value
       of derivatives..............     (26,723)       14,323          (739)          --           --
  Gain (loss) on sale of operating
     assets, net...................      (1,685)         (132)        3,130        3,637           --
                                     ----------    ----------     ---------     --------    ---------
       Net revenues................     399,568       348,860       222,433       79,125       52,355
                                     ----------    ----------     ---------     --------    ---------
</Table>


                                        35
<PAGE>


<Table>
<Caption>
                                                       YEAR ENDED DECEMBER 31, 2000
                                     ----------------------------------------------------------------
                                        2002          2001          2000          1999        1998
                                     ----------   ------------   -----------   ----------   ---------
                                                   (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                  <C>          <C>            <C>           <C>          <C>
Operating costs and expenses:
  Lease operating expenses.........      89,328        55,315        34,397       22,916       21,554
  Production taxes.................      23,954        13,407        10,631        5,742        3,888
  Transportation costs.............       7,961         5,157         3,034        1,725          850
  Exploration......................      32,390        31,313        12,790        7,314       14,664
  Depletion, depreciation and
     amortization..................     203,093       124,059        64,856       25,210       36,264
  Impairment of proved
     properties....................      19,700         9,423         2,911        3,072        8,794
  Impairment of unproved
     properties....................       9,961         6,974         5,124        2,273        1,898
  Stock compensation expense,
     net...........................       4,608           719         5,539(1)        --           --
  General and administrative.......      23,629        17,678         7,542        5,297        5,913
                                     ----------    ----------     ---------     --------    ---------
     Total operating expenses......     414,624       264,045       146,824       73,549       93,825
                                     ----------    ----------     ---------     --------    ---------
     Operating income (loss).......     (15,056)       84,815        75,609        5,576      (41,470)
Other income (expense):
  Interest expense.................     (34,836)      (13,196)       (9,731)      (9,207)      (8,323)
  Interest income..................         546         1,668         1,230          489          403
  Change in interest rate swap fair
     value.........................         226         4,960            --           --           --
  Other............................       1,002           211           152           16           29
                                     ----------    ----------     ---------     --------    ---------
Income (loss) before income
  taxes............................     (48,118)       78,458        67,260       (3,126)     (49,361)
Benefit (provision) for income
  taxes............................      19,552       (28,637)      (23,724)          --           --
                                     ----------    ----------     ---------     --------    ---------
Net income (loss)..................     (28,566)       49,821        43,536       (3,126)     (49,361)
Preferred stock dividends..........       4,762         1,587            --           --           --
                                     ----------    ----------     ---------     --------    ---------
Net income (loss) available to
  common stockholders..............  $  (33,328)   $   48,234     $  43,536     $ (3,126)   $ (49,361)
                                     ==========    ==========     =========     ========    =========
Weighted average number of common
  shares outstanding:
  Basic............................      53,007        43,408        28,296       14,727       11,004
                                     ==========    ==========     =========     ========    =========
  Diluted..........................      53,007        44,168        28,645       14,727       11,004
                                     ==========    ==========     =========     ========    =========
Net income (loss) per common share:
  Basic............................  $    (0.63)   $     1.11     $    1.54     $  (0.21)   $   (4.49)
                                     ==========    ==========     =========     ========    =========
  Diluted..........................  $    (0.63)   $     1.09     $    1.52     $  (0.21)   $   (4.49)
                                     ==========    ==========     =========     ========    =========
OTHER FINANCIAL DATA:
Net cash provided by operating
  activities.......................  $  223,197    $  195,273     $ 143,429     $ 21,279    $   7,622
Net cash provided by (used in)
  investing activities.............    (814,163)     (188,686)     (140,169)      17,981     (113,019)
Net cash provided by (used in)
  financing activities.............     606,396           843        (2,581)     (29,933)     104,667
Capital expenditures...............     827,502       194,244       146,086       14,005      113,008
BALANCE SHEET DATA (AS OF PERIOD
  END):
Cash and cash equivalents..........  $   42,761    $   27,584     $  20,154     $ 19,475    $  10,148
Working capital (deficit)..........     (11,068)       13,365        20,487       12,837      (30,993)
Total assets.......................   2,233,541     1,604,216       551,831      271,477      302,302
Total long-term debt...............     799,358       429,224           162      105,462      121,333
Total debt.........................     799,358       429,224           162      106,795      153,128
Total stockholders' equity.........   1,132,006       920,296       458,056      140,011      126,737
</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.

                                        36
<PAGE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

GENERAL

     The following information should be read in conjunction with our historical
consolidated financial statements and related notes and other financial
information included elsewhere in this report.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Our discussion and analysis of our financial condition and results of
operation are based upon consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States of America, or GAAP. The preparation of these financial statements
requires us to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses. Our significant accounting policies
are described in Note 1 to our consolidated financial statements included in
this report. In response to SEC Release No. 33-8040, "Cautionary Advice
Regarding Disclosure About Critical Accounting Policies," we have identified
certain of these policies as being of particular importance to the portrayal of
our financial position and results of operations and which require the
application of significant judgment by our management. We analyze our estimates,
including those related to oil and gas revenues, oil and gas properties, fair
value of derivative instruments, income taxes and contingencies and litigation,
and base our estimates on historical experience and various other assumptions
that we believe to be reasonable under the circumstances. Actual results may
differ from these estimates under different assumptions or conditions. We
believe the following critical accounting policies affect our more significant
judgments and estimates used in the preparation of our consolidated financial
statements:

     - Revenue Recognition.  We follow 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. No
       receivables, payables, or unearned revenue are recorded unless a working
       interest owner's aggregate sales from the property exceed its share of
       the total reserves-in-place. If such a situation arises, the parties
       would likely cash balance.

     - Successful Efforts Accounting.  We account for our 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 our oil and natural gas properties are located
       within the continental United States, the Gulf of Mexico and Canada.


     - Proved Reserve Estimates.  Estimates of our proved reserves included in
       this report are prepared in accordance with SEC guidelines. The accuracy
       of a reserve estimate is a function of:


      - the quality and quantity of available data;

      - the interpretation of that data;

      - the accuracy of various mandated economic assumptions; and

      - the judgment of the persons preparing the estimate.

      Our proved reserve information included in this report is based on
      estimates prepared by Ryder Scott Company, Netherland, Sewell &
      Associates, Inc. and our engineering staff. Estimates prepared by others
      may be higher or lower than our estimates.

      Because these estimates depend on many assumptions, all of which may
      substantially differ from actual results, reserve estimates may be
      different from the quantities of oil and natural gas that are ultimately
      recovered. In addition, results of drilling, testing and production after
      the date of an estimate may justify material revisions to the estimate.

                                        37
<PAGE>

      Our stockholders should not assume that the present value of future net
      cash flows is the current market value of our estimated proved reserves.
      In accordance with SEC requirements, we based the estimated discounted
      future net cash flows from proved reserves on prices and costs as of the
      date of the estimate. Actual future prices and costs may be materially
      higher or lower than the prices and costs as of the date of the estimate.

      Our estimates of proved reserves directly impact depletion expense. If the
      estimates of proved reserves decline, the rate at which we record
      depletion expense increases, reducing net income. Such a decline may
      result from lower market prices or increases in costs, which may make it
      uneconomic to drill for and produce higher cost fields, or property
      performance. In addition, the decline in proved reserve estimates may
      impact the outcome of our assessment of our oil and gas producing
      properties for impairment.

     - Impairment of Proved Oil and Gas Properties.  We review our long-lived
       proved properties to be held and used whenever management judges that
       events or circumstances indicate that the recorded carrying value of the
       properties may not be recoverable. Management assesses whether or not an
       impairment provision is necessary based upon management's outlook of
       future commodity prices and net cash flows that may be generated by the
       properties. Proved oil and gas properties are reviewed for impairment on
       a field-by-field basis, which is the lowest level at which depletion of
       proved properties is calculated.


     - Impairment of Goodwill.  Goodwill of a reporting unit is tested for
       impairment on an annual basis and between annual tests if an event occurs
       or circumstances change that would more likely than not reduce the fair
       value of a reporting unit below its carrying value. Management assesses
       whether or not an impairment provision is necessary based upon comparing
       the fair value of a reporting unit with its carrying value including
       goodwill. The factors used to determine fair value include estimates of
       proved reserves, future commodity prices, future production estimates,
       anticipated capital expenditures, and a discount rate commensurate with
       the risk associated with realizing the expected future cash flows.
       Management has chosen to use the traditional present value approach to
       determine the fair value as opposed to the expected present value method.
       In the traditional present value approach, a single set of estimated cash
       flows and a single interest rate (commensurate with the risk) are used to
       estimate fair value. In the expected present value approach, multiple
       cash flow scenarios reflecting the range of possible outcomes and a
       risk-free rate are used to estimate fair value. Using the expected
       present value method could result in different (and possibly higher)
       impairment charges than those calculated using the traditional present
       value method.


     - Impairment of Unproved Oil and Gas Properties.  Management periodically
       assesses individually significant unproved oil and gas properties for
       impairment, on a project-by-project basis. Management's assessment of the
       results of exploration activities, commodity price outlooks, planned
       future sales or expiration of all or a portion of such projects impact
       the amount and timing of impairment provisions.

     - Commodity Derivative Instruments and Hedging Activities.  We periodically
       enter into commodity derivative contracts and fixed-price physical
       contracts to manage our exposure to oil and natural gas price volatility.
       We primarily utilize future contracts, swaps or options, which are
       generally placed with major financial institutions or with counterparties
       of high credit quality that we believe 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 we receive. On
       January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
       Instruments and Hedging Activities." Under SFAS No. 133 all derivative
       instruments are recorded on the balance sheet at fair value. Changes in
       the derivative's fair value are recognized currently in earnings unless
       specific hedge accounting criteria are met. For qualifying cash flow
       hedges, the gain or loss on the derivative is deferred in accumulated
       other comprehensive income (loss) to the extent the hedge is effective.
       For qualifying fair value hedges, the gain or loss on the derivative is
       offset by related results of the hedged item in the income

                                        38
<PAGE>

       statement. Gains and losses on hedging instruments included in
       accumulated other comprehensive income (loss) are reclassified to oil and
       natural gas sales revenue in the period that the related production is
       delivered. Derivative contracts that do not qualify for hedge accounting
       treatment are recorded as derivative assets and liabilities at market
       value in the consolidated balance sheet, and the associated unrealized
       gains and losses are recorded as current expense or income in the
       consolidated statement of operations. While such derivative contracts do
       not qualify for hedge accounting, management believes these contracts can
       be utilized as an effective component of commodity price risk management,
       or CPRM, activities.

     - Valuation of Deferred Tax Assets.  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 basis 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.

RECENT ACCOUNTING DEVELOPMENTS


     In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 addresses
accounting and reporting for business combinations and is effective for all
business combinations initiated after June 30, 2001. SFAS No. 142 addresses the
accounting and reporting for acquired goodwill and other intangible assets.



     A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and natural gas companies. The issue is whether SFAS
No. 142 requires registrants to classify the costs of mineral rights associated
with extracting oil and natural gas as intangible assets in the balance sheet,
apart from other capitalized oil and natural gas property costs, and to provide
specific footnote disclosures. Historically, we have included the costs of
mineral/drilling rights associated with extracting oil and natural gas as
tangible assets and as a component of oil and natural gas properties. If it is
ultimately determined that SFAS No. 142 requires oil and natural gas companies
to classify costs of mineral rights associated with extracting oil and natural
gas as a separate intangible assets line item on the balance sheet, we would be
required to reclassify the amounts as follows:



<Table>
<Caption>
                                                                  DECEMBER 31,
                                                           ---------------------------
                                                               2002           2001
                                                           -------------   -----------
<S>                                                        <C>             <C>
INTANGIBLE ASSETS:
  Proved leasehold acquisition costs.....................  1,089,490,035   595,198,843
  Unproved leasehold acquisition costs...................    104,430,055   105,539,171
     Total leasehold acquisition costs...................  1,193,920,091   700,738,014
  Less accumulated depletion.............................   (168,081,488)  (88,831,502)
     Net leasehold acquisition costs.....................  1,025,838,603   611,906,512
</Table>



     Our cash flows and results of operations would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with SFAS No. 144. Further, we do not believe the classification of
the costs of mineral rights associated with extracting oil and natural gas as
intangible assets would have any impact on our compliance with covenants under
our debt agreements.



OVERVIEW


     We are an independent energy company engaged in oil and natural gas
exploitation, acquisition and exploration activities primarily in the United
States. Our reserves and production operations are concentrated in the following
diversified divisions: Northern (Rocky Mountains); Western (Uinta Basin);
Southern (Permian Basin, Mid-Continent and Gulf Coast) and Gulf of Mexico
(offshore). We focus on maintaining a balanced portfolio of lower-risk,
long-life onshore reserves and higher-margin offshore

                                        39
<PAGE>

reserves to provide a diversified cash flow foundation for our exploitation,
acquisition and exploration activities.

     Our results of operations are significantly impacted by the prices of oil
and natural gas, which are volatile. In 2002, oil and natural gas prices
increased compared to prices in 2001. Oil and natural gas prices increased from
$2.72 per Mcf and $19.78 per bbl at December 31, 2001 to $4.58 per Mcf and
$31.23 per bbl at December 31, 2002. Sales of our oil and natural gas to Dynegy
accounted for approximately 23% of our oil and natural gas sales in 2001 and
2000 and sales to EOTT Energy Corporation (an affiliate of Enron Corp.)
accounted for approximately 13% of our total oil and natural gas sales in 2000.
The operational difficulties experienced by Dynegy, Enron Corp. and EOTT Energy
Corporation had no significant impact on our results of operations or liquidity.

     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. Transportation costs are
comprised of costs paid to a carrier to deliver oil or natural gas to a
specified delivery point. In some cases we receive a payment from the purchases
of our oil and natural gas, which is net of gas transportation costs and in
other instances we pay the costs of transportation.

     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 computed using the units-of-production method based upon proved reserves. For
purposes of computing depletion, proved reserves are redetermined twice each
year. 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. 144, "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. We
estimate the expected future cash flows of our oil and gas properties, on a
field-by-field basis, and compare such future cash flows to the carrying amount
of the oil and gas properties to determine if the carrying amount is
recoverable. If the carrying amount exceeds the estimated undiscounted future
cash flows, we will adjust the carrying amount of the oil and gas properties to
fair value. The factors used to determine fair value include estimates of proved
reserves, future commodity prices, future production estimates, anticipated
capital expenditures, and a discount rate commensurate with the risk associated
with realizing the expected future cash flows. Future changes in any of the
above-referenced factors could result in us recording proved property impairment
charges in future periods. Management has chosen to use the traditional present
value approach to determine the fair value as opposed to the expected present
value method. In the traditional present value approach, a single set of
estimated cash flows and a single interest rate (commensurate with the risk) are
used to estimate fair value. In the expected present value approach, multiple
cash flow scenarios reflecting the range of possible outcomes and a risk-free
rate are used to estimate fair value. Using the expected present value method
could result in different (and possibly higher) amounts for property impairments
than those calculated using the traditional present value method. Impairments
for the years ended December 31, 2002, 2001 and 2000 were calculated based on


                                        40
<PAGE>

the following assumed oil and natural gas prices that we believe were
representative of market pricing assumptions at the time:

     - At December 31, 2002, we assumed that oil prices in 2003, 2004 and 2005
       would be $27.84, $24.09 and $23.48 per barrel, respectively, and would
       remain constant thereafter. We also assumed that natural gas prices in
       2003, 2004 and 2005 would be $4.26, $4.14 and $3.88 per Mcf,
       respectively, and would remain constant thereafter.

     - At December 31, 2001, we assumed that oil prices in 2002 would be $20.84
       per barrel and would escalate at an annual rate of 2.5% thereafter. We
       also assumed that natural gas prices in 2002 and 2003 would be $2.75 and
       $3.05 per Mcf, respectively, and would escalate at an annual rate of 2.5%
       thereafter.

     - At December 31, 2000, we assumed that oil prices in 2001 would be $24.70
       per barrel and would escalate at an annual rate of 2.5% thereafter. We
       also assumed that natural gas prices in 2001 would be $4.48 per Mcf and
       would escalate at an annual rate of 2.5% thereafter.

     In 2002 estimates of declining production were based on internal estimates
of which 81% of the net present value was evaluated or audited by independent
reserve engineers and estimated operating costs and severance taxes were based
on past experience. We also assumed at December 31, 2002 that operating and
future development costs would remain constant thereafter. At December 31, 2001
and 2000, respectively, we assumed that operating and future development costs
would escalate at an annual rate of 2.5% in 2002 and 2001, respectively. Reserve
categories used in the impairment analysis for all periods considered are
categories of proved reserves and probable and possible reserves, which were
risk adjusted based on our drilling plans and history of successfully developing
those types of reserves.


     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.
Future changes in any of the above-referenced factors could result in us
recording unproved property impairment charges in future periods.


     Stock compensation expense consists of noncash charges resulting from the
application of the provisions of FASB Interpretation No. 44 to certain stock
options granted to employees and issuance of restricted stock to certain
employees. Under Interpretation No. 44 we are required to measure compensation
cost on stock options that are considered to be variable awards until the date
of exercise, forfeiture or expiration of such options. Compensation cost is
measured for the amount of any increases in our stock price and recognized over
the remaining vesting period of the options. Any decrease in our stock price
will be recognized as a decrease in compensation cost limited to the amount of
compensation cost previously recognized as a result of an increase in our stock
price.

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

BASIS OF PRESENTATION

     Westport was formed by the merger on April 7, 2000 of Westport Oil and Gas
with EPGC. As a result of the merger, Westport Oil and Gas became a wholly owned
subsidiary of EPGC, which subsequently changed its name to Westport Resources
Corporation, and the stockholders of Westport Oil and Gas became the majority
stockholders of EPGC. 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 between EPGC and Westport Oil and Gas was
accounted for using purchase accounting with Westport Oil and Gas as the
surviving accounting entity. Westport began consolidating the results of EPGC
with the results of Westport Oil and Gas as of the April 7, 2000 closing date.

     On August 21, 2001, the stockholders of Belco approved an agreement and
plan of merger, dated as of June 8, 2001, between Belco and Westport. Pursuant
to this agreement, Westport was merged with and

                                        41
<PAGE>

into Belco, with Belco surviving and changing its name to Westport Resources
Corporation. The merger was accounted for as a purchase transaction for
financial accounting purposes with Westport as the surviving accounting entity.
Westport began consolidating the results of Belco with its results as of the
August 21, 2001 closing date.

     On September 30, 2002, we acquired oil and gas properties located in
Southeast Texas for a total cash purchase price of approximately $122 million.
We operate substantially all of the properties. The purchase also includes
10,000 net undeveloped acres and an interest in 120 square miles of 3-D seismic
data. Operations from the properties were included in 2002 for the period from
October 1, 2002 to December 31, 2002.

     On December 17, 2002, we acquired producing properties, undeveloped
leaseholds, gathering and compression facilities and other related assets in the
Greater Natural Buttes area of Uintah County, Utah from certain affiliates of El
Paso Corporation for approximately $507 million, subject to certain purchase
price adjustments. Our newly formed Western Division is comprised substantially
of these properties. Operations from the properties were included in our results
for 2002 for the period from December 17, 2002 to December 31, 2002.

RESULTS OF OPERATIONS

     The following table sets forth certain operational data for the years ended
December 31, 2002, 2001 and 2000.

                                  SUMMARY DATA


<Table>
<Caption>
                                                                FOR THE YEARS ENDED DECEMBER 31,
                                                              ------------------------------------
                                                                 2002         2001         2000
                                                              ----------   ----------   ----------
                                                              (IN THOUSANDS EXCEPT PER UNIT DATA)
<S>                                                           <C>          <C>          <C>
Production
  Oil (Mbbls)...............................................      7,927        4,929        3,584
  Natural gas (Mmcf)........................................     82,346       58,562       34,318
  Mmcfe.....................................................    129,908       88,136       55,822
Average Daily Production
  Oil (Mbbls/d).............................................       21.7         13.5          9.8
  Natural gas (Mmcf/d)......................................      225.6        160.4         93.8
  Mmcfe/d...................................................      355.9        241.5        152.5
Average prices
  Oil (per bbl).............................................   $  23.66     $  21.69     $  27.98
  Natural gas (per Mcf).....................................       2.93         3.59         4.21
  Hedging effect (per Mcfe).................................       (.01)         .02         (.44)
Oil and natural gas sales...................................   $428,430     $317,278     $244,669
Lease operating expense.....................................     89,328       55,315       34,397
  Per Mcfe..................................................       0.69         0.63         0.62
Production taxes............................................     23,954       13,407       10,631
  Per Mcfe..................................................        .18          .15          .19
Transportation costs........................................      7,961        5,157        3,034
  Per Mcfe..................................................        .06          .06          .05
General and administrative costs............................     23,629       17,678        7,542
  Per Mcfe..................................................       0.18         0.20         0.14
Depletion, depreciation and amortization....................    203,093      124,059       64,856
  Per Mcfe..................................................       1.56         1.41         1.16
</Table>


                                        42
<PAGE>

     The following is a discussion of the financial condition and results of
operations of Westport for the years ended December 31, 2002, 2001 and 2000.


     REVENUES.  Oil and natural gas revenues for 2002 increased by $111.2
million, or 35%, from $317.3 million in 2001 to $428.4 million in 2002.
Production from the acquired Belco properties and other acquisitions, including
the Williston Basin, Southeast Texas and Utah acquisitions, accounted for $113.9
million and $25.2 million, respectively, of the increase. Revenue also increased
$20.5 million from recent discoveries in the Gulf of Mexico. Oil and natural gas
revenues decreased by $36.8 million due to oil and natural gas production
declines in the Gulf of Mexico developed properties partially offset by an
increase in production volumes as a result of developmental drilling activity
and a decrease in realized average prices per Mcfe, as discussed below.
Production volumes increased 41.8 Bcfe from 88.1 Bcfe in 2001 to 129.9 Bcfe in
2002. Acquired Belco properties and other acquisitions, including the Williston
Basin, Southeast Texas and Utah acquisitions, accounted for 31.6 Bcfe and 6.6
Bcfe, respectively, of the increase. Production volumes also increased 7.0 Bcfe
from recent discoveries in the Gulf of Mexico and 1.6 Bcfe from the horizontal
drilling program in the Wiley Field. A decrease in production volumes of 4.7
Bcfe related to oil and natural gas production declines in the Gulf of Mexico
developed properties partially offset by an increase in production volumes
attributable to developmental drilling activity. Even though realized oil prices
increased 9% in 2002 compared to 2001, realized natural gas prices decreased 18%
in 2002 compared to 2001 causing the realized average prices per Mcfe to
decrease 8%. Hedging transactions had the effect of reducing oil and natural gas
revenues by $1.3 million in 2002, or $0.01 per Mcfe, and increasing oil and
natural gas revenues by $2.1 million in 2001, or $0.02 per Mcfe.


     Oil and natural gas revenues for 2001 increased by $72.6 million, or 30%,
from $244.7 million in 2000 to $317.3 million in 2001. Production from the
acquired Belco properties accounted for $49.6 million of the increase. Revenue
increased $37.1 million from recent discoveries in the Gulf of Mexico. The
increases were partially offset by decreases of 22% and 15% in realized oil and
natural gas prices, respectively. Production volumes increased 32.3 Bcfe from
55.8 Bcfe in 2000 to 88.1 Bcfe in 2001 (acquired Belco and EPGC properties
accounted for 19.2 Bcfe and 0.7 Bcfe of the increase, respectively). Production
volumes also increased 10.7 Bcfe from recent discoveries in the Gulf of Mexico,
0.6 Bcfe from coalbed methane development in the Powder River Basin area, 0.8
Bcfe from the horizontal drilling program in the Wiley Field, and 0.6 Bcfe from
the acquired interest in the Ward Estes Field in August 2000. Increases were
partially offset by declines in existing properties. Hedging transactions had
the effect of increasing oil and natural gas revenues by $2.1 million in 2001,
or $0.02 per Mcfe, and reducing oil and natural gas revenues by $24.6 million in
2000, or $0.44 per Mcfe.

     COMMODITY PRICE RISK MANAGEMENT ACTIVITIES, OR CPRM, ACTIVITIES.  The
Company recorded a net loss of $26.7 million in the non-hedge change in fair
value of derivatives in 2002 compared to a net gain of $14.3 million for 2001.
The non-hedge loss in fair value of derivatives in 2002 in the amount of $18.2
million was related to derivative contracts entered into in anticipation of the
expected production from the Acquired Properties. Upon closing of the
Acquisition, the derivative contracts qualified for hedge accounting treatment.
Net gains of $0.8 million and $15.3 million were recorded in 2002 and 2001,
respectively, for non-hedge settlements of derivatives. The gains and losses
relate to settlements of derivatives and changes in fair value of derivatives
that under SFAS No. 133 do not qualify for hedge accounting or were not
originally designated as hedges.

     For 2001, we recorded a net gain of $14.3 million in the non-hedge change
in fair value of derivatives compared to a net loss of $0.7 million for 2000. A
net gain of $15.3 million was recorded in 2001 for non-hedge settlements of
derivatives. The gains and losses relate to settlements of derivatives and
changes in fair value of derivatives that under SFAS No. 133 do not qualify for
hedge accounting or were not originally designated as hedges.

     GAIN (LOSS) ON SALE OF OPERATING ASSETS.  For 2002 and 2001, we recorded
net losses of $1.7 million and $0.1 million, respectively, on sales of non-core
operating assets compared to a net gain of $3.1 million in 2000. The gains and
losses were calculated as the difference between the sales proceeds and the
carrying value of the properties as of the date of the sale.

                                        43
<PAGE>

     LEASE OPERATING EXPENSE.  Lease operating expense for 2002 increased by
$34.0 million, or 61%, from $55.3 million in 2001 to $89.3 million in 2002.
Lease operating expenses from the acquired Belco properties and other
acquisitions, including the Williston Basin, Southeast Texas and Utah
acquisitions, accounted for $25.5 and $4.5 million, respectively, of the
increase. The remaining increase was primarily a result of increased production
from recent offshore discoveries and nonrecurring workover expense in the Gulf
of Mexico. On a per Mcfe basis, lease operating expense increased from $0.63 in
2001 to $0.69 in 2002. The increase on a per Mcfe basis was primarily due to
nonrecurring workover expense performed in 2002 at a rate of $0.06 per Mcfe.

     Lease operating expense for 2001 increased by $20.9 million, or 61%, from
$34.4 million in 2000 to $55.3 million in 2001. Lease operating expenses from
the acquired EPGC properties and Belco properties accounted for $1.3 million and
$11.4 million, respectively, of the increase. Recent discoveries in the Gulf of
Mexico, an increased level of workovers in several of our properties and a
general increase in the cost of oil field services and materials accounted for
the remainder. On a per Mcfe basis, lease operating expense remained relatively
constant at $0.62 in 2000 and $0.63 in 2001.

     PRODUCTION TAXES.  Production taxes for 2002 increased by $10.6 million, or
79%, from $13.4 million in 2001 to $24.0 million, in 2002. Acquired Belco
properties and other acquisitions, including the Williston Basin, Southeast
Texas and Utah acquisitions, accounted for $9.3 million and $2.3 million,
respectively, of the increase in production taxes. The increase from the
acquired Belco properties and other acquisitions, including the Williston Basin,
Southeast Texas and Utah acquisitions, is partially offset by a decrease in
revenue from onshore properties as a result of a decrease in realized average
oil and natural gas prices. As a percent of oil and natural gas revenues
(excluding the effects of hedges), production taxes increased from 4.2% in 2001
to 5.6% in 2002. The increase in production taxes as a percent of revenue is
primarily the result of the acquired Belco properties and other acquisitions,
which increased the number of onshore properties that are subject to production
taxes.

     Production taxes for 2001 increased by $2.8 million, or 26%, from $10.6
million in 2000 to $13.4 million, in 2001. Acquired Belco properties accounted
for $3.7 million of the increase in production taxes. The increase from the
acquired Belco properties is partially offset by a decrease in revenue from
onshore properties as a result of a decrease in realized oil and natural gas
prices. As a percent of oil and natural gas revenues (excluding the effects of
hedges), production taxes remained relatively constant at 4.3% in 2000 and 4.2%
in 2001.


     TRANSPORTATION COSTS.  Transportation costs for 2002 increased by $2.8
million, or 54%, from $5.2 million in 2001 to $8.0 million in 2002. The increase
from the acquired Belco properties accounted for $2.9 million of the increase.


     Transportation costs for 2001 increased by $2.2 million, or 70%, from $3.0
million in 2000 to $5.2 million in 2001. The increase was primarily due to
additional offshore and coalbed methane wells that started producing in the
latter part of 2000 and early 2001, which incur higher costs to transport the
natural gas.

     EXPLORATION COSTS.  Exploration costs for 2002 increased by $1.1 million,
or 3%, from $31.3 million in 2001 to $32.4 million in 2002. Exploration costs
for 2001 increased by $18.5 million, or 145%, from $12.8 million in 2000 to
$31.3 million in 2001. The following table sets forth the components of our
2002, 2001 and 2000 exploration costs:

<Table>
<Caption>
                                                           FOR THE YEAR ENDED DECEMBER 31,
                                                          ---------------------------------
                                                            2002        2001        2000
                                                          ---------   ---------   ---------
                                                                   (IN THOUSANDS)
<S>                                                       <C>         <C>         <C>
Geological and geophysical costs........................   $10,078     $ 9,877     $ 5,308
Unsuccessful property acquisitions......................       364         482         262
Delay rentals...........................................     2,401       1,681       1,200
Exploratory dry holes...................................    19,547      19,273       6,020
                                                           -------     -------     -------
                                                           $32,390     $31,313     $12,790
</Table>

                                        44
<PAGE>

     DEPLETION, DEPRECIATION AND AMORTIZATION, OR DD&A, EXPENSE.  DD&A expense
increased $79.0 million in 2002, from $124.1 million in 2001 to $203.1 million
in 2002. DD&A expense related to the acquired Belco properties and other
acquisitions, including the Williston Basin, Southeast Texas and Utah
acquisitions, caused DD&A expense to increase $53.0 million and $8.0 million,
respectively. Recent discoveries in the Gulf of Mexico caused DD&A expense to
increase $17.6 million. The remaining increase was primarily due to the
additions of oil and natural gas properties during 2002. On a per Mcfe basis,
DD&A expense increased from $1.41 to $1.56 primarily due to recent discoveries
in the Gulf of Mexico and acquired Belco properties, which have a higher DD&A
expense per Mcfe.

     DD&A expense increased $59.2 million in 2001, from $64.9 million in 2000 to
$124.1 million in 2001. Depletion related to the acquired EPGC properties and
Belco properties caused DD&A expense to increase $6.4 million and $31.7 million,
respectively. Recent discoveries in the Gulf of Mexico caused DD&A expense to
increase $14.8 million. An increase of $2.1 million was primarily due to
additions in oil and natural gas properties in northern Louisiana in 2001. The
remaining increase was primarily due to the additions of oil and natural gas
properties during 2001. These increases were the primary factors that caused
DD&A expense to increase on a per Mcfe basis from $1.16 in 2000 to $1.41 in
2001.

     IMPAIRMENT OF PROVED PROPERTIES.  During 2002, 2001 and 2000, we recognized
proved property impairments of $19.7 million, $9.4 million and $2.9 million,
respectively. In 2002, $9.7 million of these impairments were attributable to
unsuccessful development drilling in the Rocky Mountains and the remaining $10.0
million was primarily the result of a decline in oil and natural gas reserve
value due to reserve volume reductions in underperforming fields located onshore
and offshore. Impairments recorded in 2001 were as follows: $4.9 million
resulting from unsuccessful development drilling in the Rocky Mountains, $1.5
million resulting from depressed oil and natural gas prices in the Rocky
Mountains and Mid-Continent, $0.9 million resulting from unsuccessful
development drilling in the Gulf of Mexico and $2.1 million resulting from
depressed natural gas prices in the Gulf of Mexico. Impairments recorded in 2000
were mainly the result of a decline in oil and natural gas reserve value due to
reserve volume reductions in underperforming fields in Wyoming, offshore and
Louisiana.

     IMPAIRMENT OF UNPROVED PROPERTIES.  In 2002, we recognized unproved
property impairments of $10.0 million due to expired leases and from an
assessment of the exploration opportunities existing on such properties. The
impairments were for $4.0 million of leases held offshore, $3.4 million for
leases held in Wyoming, $1.6 million for leases held in Texas and the remaining
impairments were for various leases held in North Dakota and Louisiana. In 2001,
we recognized unproved property impairments of $7.0 million on offshore leases,
as a result of an assessment of the exploration opportunities existing on such
properties. In 2000, we recognized unproved property impairments of $5.1
million, as a result of an assessment of the exploration opportunities existing
on such properties. The $5.1 million consisted of $2.5 million for leases held
in North Dakota, $1.5 million for leases held offshore and $1.1 million for
various leases held in Kansas, Wyoming and Louisiana.

     STOCK COMPENSATION EXPENSE.  In 2002, we recorded $4.3 million of stock
compensation expense related to certain stock options as a result of applying
the provisions of FASB Interpretation No. 44 and recorded $0.3 million in
expense related to the issuance of restricted stock. In 2001, we recognized $0.4
million of stock compensation expense related to certain stock options as a
result of applying the provisions of FASB Interpretation No. 44 and recorded
$0.3 million in expense related to the issuance of restricted stock. In 2000, we
recognized $5.5 million of stock compensation expense due to a $3.4 million
one-time stock compensation charge related to the repurchase of employee stock
options and $2.1 million related to provisions of FASB Interpretation No. 44.

     GENERAL AND ADMINISTRATIVE, OR G&A, EXPENSE.  G&A expense increased $5.9
million in 2002, or 34%, from $17.7 million in 2001 to $23.6 million in 2002.
The merger with Belco accounted for $3.8 million of the increase. A majority of
the remaining increase was due to payroll costs resulting from an increase in
staff in 2002 reflecting expanded size and scope of our operations. On a per
Mcfe basis, G&A expense in 2002 was $0.18 compared to $0.20 in 2001.

                                        45
<PAGE>

     G&A expense increased $10.2 million in 2001, or 134%, from $7.5 million in
2000 to $17.7 million in 2001. In connection with the EPGC merger additional
employees were hired in the Houston office, which accounted for a $3.0 million
increase in G&A expense. The merger with Belco accounted for $4.2 million of the
increase. A majority of the remaining increase was due to payroll costs
resulting from an increase in staff in 2001 reflecting expanded size and scope
of our operations as a result of our reporting obligations under the Exchange
Act. On a per Mcfe basis, G&A expense in 2001 was $0.20 compared to $0.14 in
2000.

     OTHER INCOME (EXPENSE).  Other expense for 2002 was ($33.1 million)
compared to ($6.4 million) for 2001. Interest expense increased $21.6 million in
2002, as a result of the increase in the debt balance relating to the Belco
merger and the Acquisition. Other income decreased $5.1 million as compared to
2001 primarily due to a decrease of $4.7 million in changes in fair values of
interest rate swap contracts that were not designated as hedges for accounting
purposes.

     Other expense for 2001 was ($6.4 million) compared to ($8.3 million) for
2000. Interest expense increased $3.5 million in 2001, as a result of the
increase in the debt balance relating to the Merger. Other income increased $5.4
million as compared to 2000 primarily due to an increase in interest income of
$0.4 million and changes in fair values of $5.0 million on interest rate swap
contracts that were not designated as hedges for accounting purposes.

     INCOME TAXES.  We recorded an income tax benefit of $19.6 million for 2002
($17.5 million deferred and $2.1 million current) and $28.6 million income tax
expense ($26.6 million deferred and $2.0 million current) for 2001.

     We recorded income tax expense of $28.6 million ($26.6 million deferred and
$2.0 million current) for 2001 and $23.7 million ($23.0 million deferred and
$0.7 million current) for 2000.


     NET INCOME (LOSS).  Net loss for 2002 was $28.6 million compared to net
income of $49.8 million for 2001. The variance was primarily attributable to
increases in revenues of $50.7 million and the change in the income taxes from a
tax provision to a tax benefit of $48.2 million offset by increases of $150.6
million in operating expenses and $26.7 million in other expense. On a per share
basis, the 2002 net loss was ($0.63) on both a basic and fully diluted basis
compared to a $1.11 per basic share and $1.09 fully diluted for 2001 due to an
increase of 14.7 million shares outstanding and a net loss.


     Net income for 2001 was $49.8 million compared to net income of $43.5
million for 2000. The variance was primarily attributable to increases in
revenues of $126.4 million and decrease in other expense of $2.0 million offset
by increases of $117.2 million in operating expenses and $4.9 million in income
tax expense. On a per share basis net income declined to $1.11 per basic share,
$1.09 fully diluted from $1.54 per basic share, $1.52 fully diluted due to an
increase of 13.7 million shares outstanding.

LIQUIDITY AND CAPITAL RESOURCES

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

     Net cash provided by operating activities was $223.2 million for 2002
compared to $195.3 million for 2001. Net cash provided by operating activities
in 2002 increased compared to 2001 due to a 35% increase in oil and natural gas
sales as a result of the mergers with Belco and other acquisitions, including
the Williston Basin, Southeast Texas and Utah acquisitions, and recent
discoveries in the Gulf of Mexico. Net cash provided by operating activities
increased $51.9 million from $143.4 million for 2000 to $195.3 million for 2001
due to a 58% increase in production as a result of the merger with EPGC and
Belco and 2001 discoveries in the Gulf of Mexico.

     Net cash used in investing activities was $814.2 million for 2002 compared
to $188.7 million for 2001. Investing activities for 2002 include $679.9 million
used for acquisitions and $147.6 million for exploitation and exploration
activities, offset by proceeds from sales of properties of $13.3 million.
Investing activities for 2001 included $187.9 million for exploitation and
exploration activities and $6.3 million for acquisitions, offset by proceeds
from sales of properties of $5.5 million. Net cash used in investing activities
was

                                        46
<PAGE>

$188.7 million for 2001 compared to $140.2 million for 2000. Investing
activities for 2000 included $102.2 million for exploitation and exploration
activities and $43.9 million for acquisitions ($42.4 million related to the
merger with EPGC), offset by proceeds from sales of properties of $6.3 million.

     Net cash provided by financing activities was $606.4 million for 2002
compared to $0.8 million in 2001. Financing activities for 2002 consisted of
$639.0 million from the issuance of senior subordinated notes and borrowings of
long-term debt, $267.8 million from the issuance of common stock and $3.7
million from the gain on interest rate swap cancellation, offset by $285.0
million in repayment of long-term debt, new financing fees of $14.3 million and
preferred stock dividends of $4.8 million. Financing activities for 2001
consisted of $577.6 million in repayment of long-term debt, new financing fees
of $10.2 million, stock repurchases of $0.4 million and preferred stock
dividends of $1.6 million, offset by $590.0 million in borrowings and $0.6
million from the issuance of common stock. Net cash provided by financing
activities was $0.8 million for 2001 compared to net cash used in 2000 of $2.6
million. Financing activities for 2000 reflected borrowings of $50.0 million
utilized to consummate the merger with EPGC and $104.1 million from the issuance
of common stock offset by repayments of long-term debt of $156.6 million.

FINANCING ACTIVITY

     The following summarizes our contractual obligations at December 31, 2002
and the effect such obligations are expected to have on our liquidity and cash
flow in future periods.

<Table>
<Caption>
                                                           PAYMENTS DUE BY PERIOD
                                           -------------------------------------------------------
                                                      LESS THAN                            AFTER
CONTRACTUAL OBLIGATIONS                     TOTAL      1 YEAR     1-3 YEARS   3-5 YEARS   5 YEARS
-----------------------                    --------   ---------   ---------   ---------   --------
                                                               (IN THOUSANDS)
<S>                                        <C>        <C>         <C>         <C>         <C>
Long term debt(1)........................  $799,358    $   --      $   --     $207,587    $591,771
Non-cancelable operating leases..........     6,196     1,196       2,062        2,938          --
                                           --------    ------      ------     --------    --------
Total contractual cash obligations.......  $805,554    $1,196      $2,062     $210,525    $591,771
                                           ========    ======      ======     ========    ========
</Table>

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


(1) As of December 31, 2002, our long term debt was $799.358 million, consisting
    of $80 million in borrowings under the Revolving Credit Facility (with an
    average interest rate of 3.3%), $127.587 million representing the fair value
    of our outstanding 8 7/8% Senior Subordinated Notes due 2007 and $591.771
    million representing the fair value of our outstanding 8 1/4% Senior
    Subordinated Notes Due 2011. Of these amounts, $207.587 million representing
    our outstanding senior indebtedness and the fair value of our 8 7/8% Senior
    Subordinated Notes due 2007 was due between three and five years as of
    December 31, 2002. As of December 31, 2002, we intended to satisfy these
    debt obligations out of our cash flow from operations and issuance of
    additional debt securities. On April 3, 2003, we issued an additional $125
    million of our 8 1/4% Senior Subordinated Notes Due 2011 and received net
    proceeds of approximately $131.5 million from such sale. We used the
    proceeds from the sale of these notes to redeem all of our outstanding
    8 7/8% Senior Subordinated Notes due 2007 on May 5, 2003 and to reduce our
    indebtedness under the Revolving Credit Facility. On June 25, 2003, we paid
    off the remaining amounts borrowed under the Revolving Credit Facility out
    of cash flow from operations. As of September 30, 2003, we had no long term
    debt obligations due between three and five years. As of September 30, 2003,
    our long term debt obligations due after five years were $726.469 million,
    representing the fair value of our outstanding 8 1/4% Senior Subordinated
    Notes Due 2011. As of December 31, 2003, our long term debt obligations due
    between three and five years were $262 million. As of December 31, 2003, our
    long term obligations due after five years were $718.885 million,
    representing the fair value of our outstanding 8 1/4% Senior Subordinated
    Notes Due 2011.


  REVOLVING CREDIT FACILITY


     On December 17, 2002, we entered into the Revolving Credit Facility with
JPMorgan Chase Bank, Credit Suisse First Boston Corporation and certain other
lenders party thereto, as amended on October 15, 2003, to replace our previous
revolving credit facility. The Revolving Credit Facility provides for a maximum
committed amount of $600 million and an initial borrowing base of approximately
$470 million. The facility matures on December 16, 2006. We made borrowings
under the Revolving Credit Facility to


                                        47
<PAGE>

refinance our outstanding indebtedness under our previous revolving credit
facility and to pay general corporate expenses.

     Advances under the Revolving Credit Facility are in the form of either an
ABR loan or a Eurodollar loan. The interest on an ABR loan is a fluctuating rate
based upon the highest of:

     - the rate of interest announced by JP Morgan Chase Bank, formerly known as
       The Chase Manhattan Bank, as its prime rate;

     - the secondary market rate for three month certificates of deposits plus
       1%; or

     - the Federal funds effective rate plus 0.5%.

in each case plus a margin of 0% to 0.625% based upon the ratio of total debt to
EBITDAX, as defined below, and the ratings of our senior unsecured debt as
issued by Standard and Poor's Rating Group and Moody's Investor Services, Inc.
EBITDAX is a non-GAAP financial measure, which for purposes of the Revolving
Credit Facility, is defined to mean net income of the Company and its restricted
subsidiaries determined on a consolidated basis in accordance with GAAP, plus
(a) to the extent deducted from revenues in determining consolidated net income,
(i) the aggregate amount of consolidated interest expense, (ii) the aggregate
amount of letter of credit fees paid, (iii) the aggregate amount of income tax
expense and (iv) all amounts attributable to depreciation, depletion,
exploration, amortization and other non-cash charges and expenses, minus (b) to
the extent included in revenues in determining consolidated net income, all
non-cash extraordinary income, in each case determined on a consolidated basis
in accordance with GAAP and without duplication of amounts.

     The interest on a Eurodollar loan is a fluctuating rate based upon the rate
at which Eurodollar deposits in the London interbank market are quoted plus a
margin of 1.000% to 1.875% based upon the ratio of total debt to EBITDAX and the
ratings of our senior unsecured debt as issued by Standard and Poor's Rating
Group and Moody's Investor Service, Inc.

     The Revolving Credit Facility contains various covenants and default
provisions applicable to us and our restricted subsidiaries, including two
financial covenants that require us to maintain a current ratio of not less than
1.0 to 1.0 and a ratio of EBITDAX to consolidated interest expense for the
preceding four consecutive fiscal quarters of not less than 3.0 to 1.0.
Commitment fees under the Revolving Credit Facility range from 0.25% to 0.5% on
the average daily amount of the available unused borrowing capacity based on the
rating of our senior unsecured debt as issued by Standard and Poor's Rating
Group and Moody's Investor Service, Inc.

     Under the terms of the Revolving Credit Facility the we must meet certain
tests before we are able to declare or pay any dividend on (other than dividends
payable solely in equity interests of the Company other than disqualified
stock), or make any payment of, or set apart assets for a sinking or other
analogous fund for the purchase, redemption, defeasance, retirement or other
acquisition of, any shares of any class of equity interests of us or any of our
restricted subsidiary, whether now or hereafter outstanding, or make any other
distribution in respect thereof, either directly or indirectly, whether in cash
or property or in obligations of the Company or any restricted subsidiary. Other
covenants include restrictions on incurring additional indebtedness, liens, and
guarantee obligations; limitations on fundamental changes and sales of assets;
restrictions on making certain investments, loans or advances; limitations on
optional redemption of subordinated indebtedness; restrictions on transacting
with affiliates, changing lines of business and entering into certain hedging
agreements; and limitations on sale and leasebacks and use of proceeds.


     As of December 31, 2002, we had borrowings of $80.0 million (with an
average interest rate of 3.3%) and letters of credit issued of approximately
$17.1 million outstanding under the Revolving Credit Facility, and available
unused borrowing capacity of approximately $372.9 million. On June 25, 2003, we
paid off the amounts borrowed under the Revolving Credit Facility out of cash
flow from operations and by using a portion of the proceeds received from the
sale of our 8 1/4% Senior Subordinated Notes Due 2011 issued on April 3, 2003
(see below). As of September 30, 2003, we had no borrowings under the Revolving
Credit Facility and letters of credit of approximately $40.4 million. Available
unused borrowing capacity was


                                        48
<PAGE>


approximately $429.6 million as of such date. As of December 31, 2003, we had
$262 million outstanding under the Revolving Credit Facility and letters of
credit of approximately $73.6 million, with available unused borrowing capacity
of approximately $164.4 million. The letters of credit were issued primarily in
connection with the margin requirements of our oil and gas derivative contracts.
Prior to the October 15, 2003 amendment, the Revolving Credit Facility limited
the outstanding letters of credit to $200 million. As of October 15, 2003, the
Revolving Credit Facility no longer imposes a limit on the outstanding letters
of credit, provided that the amount of letters of credit outstanding on any date
does not exceed the lesser of the aggregate commitments under the Revolving
Credit Facility and the borrowing base then in effect, or if the borrowing base
is not in effect on such date, the aggregate commitments under the Revolving
Credit Facility.



     The October 15, 2003 amendment increased the borrowing base from $470
million to $500 million. The amendment also increased the basket allowed for
purposes of providing cash collateral from $10 million to $20 million and
deleted the requirement to file liens on properties if not rated BB+ and Ba1 at
December 31, 2003.


  8 1/4% SENIOR SUBORDINATED NOTES DUE 2011

     On December 17, 2002, we issued $300 million in additional principal amount
of our 8 1/4% Senior Subordinated Notes Due 2011 pursuant to Rule 144A and
Regulation S under the Securities Act at a price of 103% of the principal
amount, with accrued interest from November 1, 2002. The 2002 notes were issued
as additional debt securities under an indenture pursuant to which, on November
5, 2001, we issued $275 million of our 8 1/4% Senior Subordinated Notes Due
2011. All of the 2001 and 2002 notes were subsequently exchanged on March 14,
2002 and March 12, 2003, respectively, for equal principal amounts of notes
having substantially identical terms and registered under the Securities Act. On
April 3, 2003, we issued an additional $125 million of our Senior Subordinated
Notes Due 2011 under the same indenture pursuant to Rule 144A and Regulation S
under the Securities Act at a price of 106% of the principal amount, with
accrued interest from November 1, 2002. All of our 8 1/4% Senior Subordinated
Notes Due 2011 constitute a single class of debt securities under the indenture
relating to these notes. These notes are senior subordinated unsecured
obligations of Westport and are jointly and severally guaranteed, on a senior
subordinated basis, by some of our existing and future restricted subsidiaries.
These notes mature on November 1, 2011. We pay interest on these notes
semiannually on May 1 and November 1. Our first interest on the 2003 notes was
paid on May 1, 2003. We used the proceeds from the sale of the 2003 notes to
redeem all of our outstanding 8 7/8% Senior Subordinated Notes due 2007
(described below) and to reduce our indebtedness under the Revolving Credit
Facility. We are entitled to redeem our 8 1/4% Senior Subordinated Notes Due
2011 in whole or in part on or after November 1, 2006 for the redemption price
set forth in these notes. Prior to November 1, 2006, we are entitled to redeem
these notes, in whole but not in part, at a redemption price equal to the
principal amount of the notes plus a premium. There is no sinking fund for these
notes.

     The Indenture governing the notes limits what we and our restricted
subsidiaries do. The provisions of the Indenture limit our and such subsidiaries
ability to incur additional indebtedness; pay dividends on our capital stock or
redeem, repurchase or retire our capital stock or subordinated indebtedness;
make investments; incur liens; create any consensual limitation on the ability
of our restricted subsidiaries to pay dividends, make loans or transfer property
to us; engage in transactions with our affiliates; sell assets, including
capital stock of our subsidiaries; and consolidate, merge or transfer assets.
During any period that the notes have investment grade ratings from both Moody's
Investors Service, Inc. and Standard and Poor's Ratings Group and no default has
occurred and is continuing, the foregoing covenants will cease to be in effect
with the exception of covenants that contain limitations on liens and on, among
other things, certain consolidations, mergers and transfers of assets. The notes
do not currently qualify as investment grade.


     We have agreed to file an exchange offer registration statement or, under
certain circumstances, a shelf registration statement pursuant to a registration
rights agreement relating to the 2003 notes. On June 4, 2003, we filed an
exchange offer registration statement, as amended on September 12, 2003,


                                        49
<PAGE>


relating to the 2003 notes. On November 1, 2003, we paid additional interest of
0.5% per annum on the 2003 notes, which accrued from October 1, 2003, and will
continue to pay such additional interest, accruing from November 1, 2003 until
such time as the SEC declares our registration statement relating to the 2003
notes effective and we consummate the exchange offer contemplated therein. The
2003 notes are eligible for trading in The PORTAL(SM) Market, a subsidiary of
The Nasdaq Stock Market, Inc.


  8 7/8% SENIOR SUBORDINATED NOTES DUE 2007

     In connection with the merger with Belco, we assumed $147 million face
amount, $149 million fair value, of Belco's 8 7/8% Senior Subordinated Notes due
2007. On November 1, 2001, approximately $24.3 million face amount of these
notes was tendered to us pursuant to the change of control provisions of the
related indenture. The tender price was equal to 101% of the principal amount of
each note plus accrued and unpaid interest as of October 29, 2001. Including the
premium and accrued interest, the total amount paid was $24.8 million. We used
borrowings under our revolving credit facility to fund the repayment. No gain or
loss was recorded in connection with the redemption as the fair value of the
8 7/8% Senior Subordinated Notes recorded in connection with the merger with
Belco equaled the redemption cost. On May 5, 2003 we redeemed all of our
outstanding 8 7/8% Senior Subordinated Notes due 2007 in the aggregate principal
amount of approximately $123 million at a total redemption price of
approximately $129.6 million. The redemption was funded with the proceeds from
the sale of $125 million of our 8 1/4% Senior Subordinated Notes Due 2011 issued
on April 3, 2003. The remaining proceeds were used to reduce our indebtedness
under the Revolving Credit Facility.

 PRIVATE EQUITY OFFERING

     On November 19, 2002, we completed the private equity offering of 3.125
million shares of our common stock to Spindrift Partners, L.P., Spindrift
Investors (Bermuda) L.P., Global Natural Resources III and Global Natural
Resources III L.P. at a net price to us of $16.00 per share for aggregate
proceeds of $50 million. The purchasers may be prohibited from selling this
common stock at our option for up to 187 days in the event we pursue a public
equity offering during the next two years. The terms of the sale were negotiated
on November 11, 2002 and the net price represents a 9% discount from the closing
price of our common stock on the New York Stock Exchange as of that date.

     In connection with the private equity offering, we agreed to file a shelf
registration statement registering the resale by the selling stockholders from
time to time of the common stock we issued in the private equity offering. We
also agreed to use our reasonable best efforts to cause the registration
statement to become effective within 90 days of the closing of the private
equity offering. In addition, we agreed, subject to certain rights of
suspension, to keep such registration statement effective until the earlier of
(1) the date on which all of the shares have been (a) sold under the
registration statement or (b) distributed pursuant to Rule 144(k) under the
Securities Act or (2) two years after the date of the stock purchase agreement.
On December 31, 2002, we filed the shelf registration statement registering the
resale by the selling stockholders from time to time of our common stock issued
in the private equity offering, which registration statement was declared
effective by the SEC on January 7, 2003.

  SHELF OFFERING

     On December 16, 2002, we closed the shelf offering of 11.5 million shares
of common stock at a price of $19.90 per share, which includes 1.5 million
shares covered by an over-allotment option we granted to, and which was
exercised by, the underwriters. We received net proceeds of approximately $216.2
million from the sale of our common stock, which we used to finance, in part,
the Acquisition.

  CAPITAL EXPENDITURES


     We anticipate that our capital expenditures, excluding acquisitions, for
2003 will be approximately $270 million, with approximately 72% allocated for
exploitation and 28% for exploration. Our capital expenditures for 2002 were
$147.6 million, excluding acquisitions of $679.9 million and geological and
geophysical costs of $10.1 million. We anticipate that our primary cash
requirements for 2003 will include


                                        50
<PAGE>

funding acquisitions, funding development projects and general working capital
needs. We will continue to seek opportunities for acquisitions of proved
reserves with substantial exploitation and exploration potential. The size and
timing of capital requirements for acquisitions is inherently unpredictable and
we therefore do not budget for them. We expect to fund our capital expenditure
activities, which include acquisition, development of and exploration on our oil
and gas properties through cash flow from operations and available capacity
under our Revolving Credit Facility.

     We believe that borrowings under the Revolving Credit Facility, projected
operating cash flows and cash on hand will be sufficient 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. Actual levels of
capital expenditures may vary significantly due to a variety of factors,
including but not limited to:

     - drilling results;

     - product prices;

     - industry conditions and outlook; and

     - future acquisition of properties.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We periodically enter into commodity price risk management, or CPRM,
transactions to manage our exposure to oil and gas price volatility. CPRM
transactions may take the form of futures contracts, swaps or options. All CPRM
data is presented in accordance with requirements of SFAS No. 133, which the
Company adopted on January 1, 2001. Accordingly, unrealized gains and losses
related to the change in fair market value of derivative contracts that qualify
and are designated as cash flow hedges are recorded as other comprehensive
income or loss and such amounts are reclassified to oil and gas sales revenues
as the associated production occurs. Derivative contracts that do not qualify
for hedge accounting treatment are recorded as derivative assets and liabilities
at market value in the consolidated balance sheet, and the associated unrealized
gains and losses are recorded as current expense or income in the consolidated
statement of operations. While such derivative contracts do not qualify for
hedge accounting, management believes these contracts can be utilized as an
effective component of CPRM activities.

     For 2002 we recorded increases in operating revenues from non-hedge CPRM
settlements in the amount of $0.8 million, which includes ($2.9) million of cash
settlements and non-hedge change in fair value of derivatives of ($26.7)
million, including ($0.1) million of ineffectiveness. The majority or $18.2
million of the non-hedge loss in fair value of derivatives was related to
derivative contracts entered into in anticipation of the expected production
from the Acquired Properties. Upon closing of the Acquisition, the derivative
contracts qualified for hedge accounting treatment.

     For 2002, we recorded hedging settlement losses in the amount of $1.3
million, which includes cash losses of $8.2 million.

     For 2001, we recorded increases in operating revenues from non-hedge CPRM
settlements in the amount of $15.3 million, which includes $3.6 million of cash
settlements and non-hedge change in fair value of derivatives of $14.3 million.
For 2000, we recorded a decrease in operating revenues from non-hedge change in
fair value of derivatives of $0.7 million.

     For 2001, we recorded hedging settlement gains in the amount of $2.1
million, which include cash losses of $4.5 million and for 2000 hedging
settlement losses of $24.6 million.

     As of February 19, 2003, we have approximately 5.2 million barrels of oil
and 73.7 Bcf of natural gas subject to CPRM contracts for 2003. Of these
contracts, all of the oil and 63.4 Bcf of the natural gas contracts are subject
to weighted average NYMEX floor prices of $23.18 per barrel and $3.78 per Mmbtu
and weighted average NYMEX ceiling prices of $25.16 per barrel and $4.20 per
Mmbtu, respectively, excluding the effect, if any, of the three-way floor price.
Of the remaining 2003 gas CPRM contracts,

                                        51
<PAGE>

7.3 Bcf have settlements that are calculated based on the Northwest Pipeline
Rocky Mountain Index, or NWPRM, with weighted average NWPRM floor and ceiling
prices of $3.00 and $3.29, respectively. The remaining 2003 gas CPRM contract
settlements are calculated based on the Colorado Interstate Gas Index, or CIG,
with a weighted average swap price of $3.59. In addition, included in the 63.4
Bcf of natural gas contracts, we entered into basis swaps covering 13.4 Bcf of
natural gas for 2003 that lock in the pricing differential between NYMEX and
NWPRM at a weighted average price differential of $0.67 per Mmbtu and 3.7 Bcf
for 2003 that lock in the pricing differential between NYMEX and CIG at a
weighted average price differential of $0.95 per Mmbtu. We have approximately
2.2 million barrels of oil and 49.3 Bcf of natural gas subject to CPRM contracts
for 2004. Of these contracts, all of the oil and 38.3 Bcf of the natural gas
contracts are subject to weighted average NYMEX floor prices of $23.93 per
barrel and $3.83 per Mmbtu and weighted average NYMEX ceiling prices of $25.47
per barrel and $4.06 per Mmbtu, respectively, excluding the effect, if any, of
the three-way floor price. The remaining 2004 gas CPRM contract settlements are
calculated based on the NWPRM Index with weighted average swap price of $3.33.
In addition, included in the 38.3 Bcf of natural gas contracts, we entered into
basis swaps covering 3.7 Bcf of natural gas for 2004 that lock in the pricing
differential between NYMEX and NWPRM at a weighted average price differential of
$0.66 per Mmbtu and 1.8 Bcf of natural gas for 2004 that lock in the pricing
differential between NYMEX and CIG at a weighted average differential of $0.81.
We have approximately 9.1 Bcf of natural gas subject to CPRM contracts for 2005
with a weighted average NYMEX swap price of $3.96 per Mmbtu. The contracts
discussed above represent our hedge and non-hedge positions.

     The tables below provide details about the volumes and prices of all open
CPRM commitments, hedge and non-hedge, as of February 19, 2003:

<Table>
<Caption>
                                                                2003       2004      2005
                                                              --------   --------   ------
<S>                                                           <C>        <C>        <C>
HEDGES
GAS
  NYMEX Price Swaps Sold -- receive fixed price (thousand
     Mmbtu)(1)..............................................    31,950     18,300    9,125
     Average price, per Mmbtu...............................  $   4.01   $   3.92   $ 3.96
  NWPRM Price Swaps Sold -- receive fixed price (thousand
     Mmbtu)(2)..............................................        --     10,980       --
     Average price, per Mmbtu...............................        --   $   3.33       --
  CIG Price Swaps Sold -- receive fixed price (thousand
     Mmbtu)(3)..............................................     3,060         --       --
     Average price, per Mmbtu...............................  $   3.59         --       --
  NYMEX Collars Sold (thousand Mmbtu)(4)....................    23,383     16,380       --
     Average floor price, per Mmbtu.........................  $   3.61   $   3.70       --
     Average ceiling price, per Mmbtu.......................  $   4.29   $   4.00       --
  NWPRM Collars Sold (thousand Mmbtu)(5)....................     7,300         --       --
     Average floor price, per Mmbtu.........................  $   3.00         --       --
     Average ceiling price, per Mmbtu.......................  $   3.29         --       --
  NYMEX Three-way Collars (thousand Mmbtu)(4),(6)...........     8,030      3,660       --
     Average floor price, per Mmbtu.........................  $   3.39   $   4.00       --
     Average ceiling price, per Mmbtu.......................  $   4.73   $   5.00       --
     Three-way average floor price, per Mmbtu...............  $   2.22   $   3.15       --
  Basis Swaps(7)
     NWPRM (thousand Mmbtu).................................    13,430      3,660       --
       Average differential price, per Mmbtu................  $   0.67   $   0.66       --
     CIG (thousand Mmbtu)...................................     3,650      1,830       --
       Average differential price, per Mmbtu................  $   0.95   $   0.81       --
</Table>

                                        52
<PAGE>

<Table>
<Caption>
                                                                2003       2004      2005
                                                              --------   --------   ------
<S>                                                           <C>        <C>        <C>
OIL
  NYMEX Price Swaps Sold -- receive fixed price
     (Mbbls)(1).............................................       875      1,098       --
     Average price, per bbl.................................  $  21.80   $  24.02       --
  NYMEX Collars Sold (Mbbls)(4).............................     1,980         --       --
     Average floor price, per bbl...........................  $  24.45         --       --
     Average ceiling price, per bbl.........................  $  26.45         --       --
  NYMEX Three-way Collars (Mbbls)(4),(6)....................     1,995      1,098       --
     Average floor price, per bbl...........................  $  23.18   $  23.83       --
     Average ceiling price, per bbl.........................  $  26.30   $  26.92       --
     Three-way average floor price, per bbl.................  $  18.90   $  19.00       --
NON-HEDGES
OIL
  NYMEX Price Swaps Sold, receive fixed price (Mbbls)(1)....       300         --       --
     Average price per bbl..................................  $  18.86         --       --
ESTIMATED FAIR VALUE OF OIL AND GAS DERIVATIVES AS OF
  DECEMBER 31, 2002 (IN THOUSANDS)..........................  $(42,157)  $(13,475)  $ (165)
</Table>

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

(1) For any particular NYMEX swap sold transaction, the counterparty is required
    to make a payment to Westport in the event that the NYMEX Reference Price
    for any settlement period is less than the swap price for such hedge, and we
    are required to make a payment to the counterparty in the event that the
    NYMEX Reference Price for any settlement period is greater than the swap
    price for such hedge.

(2) For any particular NWPRM swap sold transaction, the counterparty is required
    to make a payment to Westport in the event that the NWPRM Index Price for
    any settlement period is less than the swap price for such hedge, and we are
    required to make a payment to the counterparty in the event that the NWPRM
    Index Price for any settlement period is greater than the swap price for
    such hedge.

(3) For any particular CIG swap sold transaction, the counterparty is required
    to make a payment to Westport in the event that the CIG Index Price for any
    settlement period is less than the swap price for such hedge, and we are
    required to make a payment to the counterparty in the event that the CIG
    Index Price for any settlement period is greater than the swap price for
    such hedge.

(4) For any particular NYMEX collar transaction, the counterparty is required to
    make a payment to Westport if the average NYMEX Reference Price for the
    reference period is below the floor price for such transaction, and we are
    required to make payment to the counterparty if the average NYMEX Reference
    Price is above the ceiling price of such transaction.

(5) For any particular NWPRM collar transaction, the counterparty is required to
    make a payment to Westport if the average NWPRM Index Price for the
    reference period is below the floor price for such transaction, and we are
    required to make payment to the counterparty if the average NWPRM Index
    Price is above the ceiling price of such transaction.

(6) Three way collars are settled as described in footnote (4) above, with the
    following exception: if the NYMEX Reference Price falls below the three-way
    floor price, the average floor price is reduced by the amount the NYMEX
    Reference Price is below the three-way floor price. For example, if the
    NYMEX Reference Price is $18.00 per bbl during the term of the 2002
    three-way collars, then the effective average floor price would be $22.28
    per bbl.

(7) For any particular basis swap, the counterparty is required to make a
    payment to Westport in the event that the difference between the NYMEX
    Reference Price and the applicable published index (NWPRM or CIG) for any
    settlement period is greater than the swap differential price for such
    hedge, and Westport is required to make a payment to the counterparty in the
    event that the difference between the NYMEX Reference Price and the
    applicable published index (NMPRM or CIG) for any settlement period is less
    than the swap differential price for such hedge.

                                        53
<PAGE>

INTEREST RATE SWAP AGREEMENTS

     The following table summarizes the interest rate swap contracts we
currently have in place:

<Table>
<Caption>
                                                          CURRENT
NOTIONAL AMOUNT  TRANSACTION DATE   EXPIRATION DATE    ESTIMATED RATE
---------------  ----------------   ---------------    --------------
<S>              <C>                <C>                <C>
 $100 million    November 2001      November 1, 2011   LIBOR + 2.42%
 $ 50 million     January 2003      November 1, 2011   LIBOR + 3.37%
 $ 40 million     January 2003      November 1, 2011   LIBOR + 3.55%
 $ 50 million    February 2003      November 1, 2011   LIBOR + 3.42%
</Table>

     We entered into the interest rate swap contracts above to hedge the fair
value of a portion of the 8 1/4% Senior Subordinated notes. Because these swaps
meet the conditions to qualify for the "short cut" method of assessing
effectiveness under the provisions of SFAS 133, the change in the fair value of
the debt is assumed to equal the change in the fair value of the interest rate
swap. As such, there is no ineffectiveness assumed to exist between the interest
rate swap and the notes.

     The interest rate swaps are fixed for floating swaps in that we receive the
fixed rate of 8.25% and pay the floating rate. The floating rate is redetermined
every six months based on the LIBOR rate in effect at the contractual reset
date. When LIBOR plus the applicable margin shown above is less than 8.25%, we
receive a payment from the counterparty equal to the difference in rate times
the notional amount. When LIBOR plus the applicable margin shown above is
greater than 8.25%, we pay the counterparty the difference in rate times the
notional amount. As of December 31, 2002, we recorded a derivative asset of $7.9
million related to the interest rate swaps, which have been designated as fair
value hedges, with a corresponding debt increase. Based on the fair value of the
interest rate swaps at December 31, 2002, we could expect to receive cash flows
of approximately $860,000 per year.

     In September 2002, we terminated an interest rate swap on the 8 7/8% Senior
Subordinated Notes resulting in the receipt of a $3.7 million fair value gain,
which was added to the outstanding debt balance and will be amortized over the
remaining life of the note.

     For 2002, we recorded other income of $0.2 million related to the change in
fair value of the non-hedge interest rate swap.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Our financial statements begin on page F-1 of this Form 10-K.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

     There have been no disagreements with our independent accountants on our
accounting or financial reporting that would require our independent accountants
to qualify or disclaim their report on our financial statements, or otherwise
require disclosure in this Form 10-K.

     On April 9, 2002, we dismissed Arthur Andersen LLP, also referred to as
Andersen, as our independent accountants effective as of that date. The decision
to dismiss Andersen was recommended by the Audit Committee of the Board of
Directors and was approved by the Board of Directors on April 9, 2002.

     Andersen's report on the Company's financial statements for the fiscal year
ended December 31, 2001 did not contain an adverse opinion or disclaimer of
opinion and was not qualified or modified as to uncertainty or audit scope. In
addition, there were no modifications as to accounting principles except that
the audit report of Andersen for the fiscal year ended December 31, 2001
contained an explanatory paragraph with respect to the change in the method of
accounting for derivative instruments effective January 1, 2001 as required by
the Financial Accounting Standards Board. During fiscal year ended December 31,
2001 and the period from January 1, 2002 through the date of Andersen's
termination, there

                                        54
<PAGE>

were no disagreements between us and Andersen on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure, which disagreements, if not resolved to the satisfaction of Andersen,
pursuant to Item 304(a)(1) of Regulation S-K, would have caused it to make
reference to the subject matter of the disagreements in its report.

     In April of 2002 as required under the regulations of the Securities and
Exchange Commission, or the SEC, we provided Andersen with a copy of our
disclosure in connection with this matter and requested Andersen to furnish us
with a letter addressed to the SEC stating whether it agreed with our statements
and, if not, stating the respects in which it did not agree. Andersen's letter
was filed as Exhibit 16.1 to our Current Report on Form 8-K filed with the SEC
on April 15, 2002.

     Effective April 9, 2002, we engaged KPMG LLP, or KPMG, as our new
independent accountants for the fiscal year ending December 31, 2002. The
decision to appoint KPMG was recommended by the Audit Committee of the Board of
Directors and was approved by the Board of Directors on April 9, 2002.

     During the two most recent fiscal years and through the date of Andersen's
termination, we did not consult with KPMG regarding any of the matters or events
set forth in Item 304(a)(2) of Regulation S-K.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT


                                   MANAGEMENT



     The following table sets forth certain information with respect to the
executive officers and directors of Westport as of December 31, 2003.



<Table>
<Caption>
NAME                                    AGE                  POSITION
----                                    ---                  --------
<S>                                     <C>   <C>
Donald D. Wolf........................  59    Chairman of the Board and Chief
                                              Executive Officer
Barth E. Whitham......................  46    President and Chief Operating Officer
Lon McCain............................  55    Vice President, Chief Financial
                                              Officer and Treasurer
Grant W. Henderson....................  44    Executive Vice President and General
                                              Manager -- Southern Division
Kenneth D. Anderson...................  60    Vice President -- Accounting
Brian K. Bess.........................  42    Vice President -- Engineering
Howard L. Boigon......................  56    Vice President, General Counsel and
                                              Secretary
Carter Mathies........................  47    Vice President and General Manager --
                                              Western Division
Peter M. Mueller......................  49    Vice President and General Manager
                                              Northern -- Division
Michael L. Beatty(1)..................  56    Director
Laurence D. Belfer(1).................  36    Director
Richard D. Dole(2)....................  58    Director
James M. Funk.........................  53    Director
David L. Porges.......................  45    Director
Michael Russell(1)....................  53    Director
Robert F. Semmens(3)..................  46    Director
Randy Stein(1)(2)(3)..................  49    Director
William F. Wallace(1)(2)(3)...........  63    Director
</Table>


                                        55
<PAGE>

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


(1) Member of the Nominating and Governance Committee.



(2) Member of the Audit Committee.



(3) Member of the Compensation Committee.



     Donald D. Wolf has served as Chairman of the Board and Chief Executive
Officer since joining Westport in June 1996 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 a director of MarkWest
Hydrocarbon, Inc. and Aspect Resources LLC.



     Barth E. Whitham has served as President and Chief Operating Officer of
Westport since June 1996, President since 1994 and an officer since Westport's
inception in 1991. Prior to joining Westport, Mr. Whitham was Manager of
Production Operations for the Caza companies. From 1979 to 1991, Mr. Whitham was
associated with 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.



     Lon McCain has served as Vice President and Chief Financial Officer since
joining Westport in April of 2001. Prior to joining Westport, Mr. McCain served
for eight years as Senior Vice President and Principal with Petrie Parkman & Co.
where he was involved with the firm's capital market activities. He has over 15
years experience as a senior financial executive with independent oil and
natural gas companies. Mr. McCain has taught as an adjunct professor since 1982
at the University of Denver's Graduate School of Business.



     Grant W. Henderson has served as Executive Vice President and General
Manager -- Southern Division since August of 2001. Prior to August 2001, Mr.
Henderson served as President and Chief Operating officer of Belco Oil & Gas
Corp. Prior to his tenure at Belco, Mr. Henderson was President and Chief
Financial Officer of Coda Energy, Inc. From 1981 until he joined Coda Energy,
Inc. in 1993, Mr. Henderson was employed by NationsBank (now Bank of America
N.A.), last serving as Senior Vice President in its Energy Banking Group.



     Kenneth D. Anderson has served as Vice President -- Accounting since April
2000. Mr. Anderson joined Westport in September 1991 as Controller. Prior to
joining Westport, he was involved in the financial management of oil and natural
gas exploration and production companies.



     Brian K. Bess has served as Vice President -- Engineering since joining
Westport in May 1998. Prior to joining Westport, Mr. Bess was the Acquisitions
and Reservoir Manager for General Atlantic Resources/UMC Petroleum Corp. from
February 1993 until May 1998. He previously has held various engineering
positions with Petro-Lewis Corp., Energy Investment Management, and General
Royalty Companies, as well as various consulting assignments.



     Howard L. Boigon has served as Vice President, General Counsel and
Secretary since May 2001. Mr. Boigon served in the same positions and as a
director of Basin Exploration, Inc. from 1992 until its merger with Stone Energy
Corporation on February 1, 2001. Prior to joining Basin Exploration, Mr. Boigon
was with the Denver law firm of Davis, Graham & Stubbs for 18 years, where he
specialized in the practice of natural resources law.



     Carter Mathies has served as Vice President and General Manager -- Western
Division since February 1, 2003. Prior to joining Westport, Mr. Mathies was Vice
President of Kinder Morgan Energy Partners, L.P. Previously he had been the
Chief Executive Officer of Tipperary Corporation.


                                        56
<PAGE>


     Peter M. Mueller has served as Vice President and General
Manager -- Northern Division since June 9, 2003. Prior to joining Westport, Mr.
Mueler was Principal and Director of Oil and Gas Services of R.W. Beck. Prior to
joining R.W. Beck, Mr. Mueler worked for Amoco Corporation as Manager of the San
Juan Basin Resource Development in Colorado and the Resource Manager of the Red
Oak Field in Oklahoma.



     Michael L. Beatty has served as a Director of Westport since October 1,
2003. Mr. Beatty is the owner of The Beatty Law Firm in Denver, Colorado since
October 1, 1998 and was previously of counsel with the law firm of Akin Gump
Strauss Hauer & Feld LLP. Mr. Beatty previously served as Executive Vice
President, General Counsel and director of Coastal Corporation and as General
Counsel of Colorado Interstate Gas Company. Prior to joining Colorado Interstate
Gas Company, Mr. Beatty was a tenured professor of law at the University of
Idaho. From 1993 until 1995, Mr. Beatty served as Chief of Staff to Colorado
Governor Roy Romer.



     Laurence D. Belfer has served as a Director of Westport since August 2001.
Mr. Belfer was a director of Belco from 1996 until August 2001. Mr. Belfer
joined Belco as Vice President in September 1992. He was promoted to Executive
Vice President in May 1995 and Chief Operating Officer in December 1995, was
named President in April 1997 and Vice Chairman in March 1999. He is a founder
and Chairman of Harvest Management, Inc., a money management firm, and is
President of Belfer Management LLC, a family investment firm.



     Richard D. Dole has served as a Director of Westport since October 1, 2003.
Mr. Dole is currently President and co-founder and serves on the Board of
Members of Benefits Access Solutions, LLC and previously was Managing Partner of
Innovation Group Partners, LLC. Prior to founding Innovation Growth Partners in
2000, Mr. Dole served from 1998 until 2000 as Vice President and Chief Financial
Officer of Burlington Resources International. From 1995 until 1998, Mr. Dole
was national partner-in-charge of business process solutions of KPMG LLP. Prior
to 1995, he held various positions with Coopers & Lybrand, LLP, including Vice
Chairman -- process management, Southwest Region Director of merger, acquisition
and corporate finance services, and National Chairman for the energy and natural
resources industry practices.



     James M. Funk has served as a Director of Westport since April 2000. Mr.
Funk joined Equitable Resources, Inc. in June 2000 and served as president,
Equitable Production Company until December 2003. From February 1999 through
June 2000, Mr. Funk was an independent consultant. 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.



     David L. Porges has served as a Director of Westport since April 2000. Mr.
Porges is Executive Vice President, Chief Financial Officer and a Director 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 more than 20 years.



     Michael Russell has served as a Director of Westport since April 2000. He
was a director of Westport Oil and Gas and served as its President from its
inception through June 1996. 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 a major stockholder of
Westport. Mr. Russell has worked for Dr. Richard J. Haas Partners for the past
29 years. He has been involved in the U.S. oil and natural gas industry for the
past 22 years. Together with senior partner Dr. Richard J. Haas, he was
responsible for starting in 1981 the original U.S. oil and natural gas
operations that led to the formation of Westport Oil and Gas. Mr. Russell was
called to the bar at Lincoln's Inn, London.


                                        57
<PAGE>


     Robert F. Semmens has served as a Director of Westport since October 1,
2003. Mr. Semmens is currently an Adjunct Professor of finance at the Leonard N.
Stern School of Business at New York University and a private investor. From
1993 until 2000 when the company was sold, Mr. Semmens was a Principal of the
Beacon Group, a private investment and advisory firm specializing in energy
investment. Prior to co-founding the Beacon Group, Mr. Semmens was with the
investment banking division of Goldman, Sachs & Co. where he specialized in
corporate finance primarily in the energy industry.



     Randy Stein has served as a Director of Westport 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. 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 also serves as a Director of Koala Corporation.



     William F. Wallace has served as a Director of Westport since April 2000.
Mr. Wallace was a Director of Westport Oil and Gas prior to its merger with
EPGC. He also serves on the board of directors of Khanty Mansiysk Oil Corp. and
served on the board of directors of Input/Output, Inc. until his term expired on
May 21, 2002. 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 23 years with Texaco Inc.,
including six years as Vice President of Exploration for Texaco USA and as
Regional Vice President of Texaco's Eastern Region.



EMPLOYMENT AGREEMENTS



     We are party to employment agreements entered into effective April 1, 2002
with each of Donald D. Wolf and Barth E. Whitham, pursuant to which Messrs. Wolf
and Whitham serve as Westport's Chairman of the Board and Chief Executive
Officer and its President and Chief Operating Officer, respectively. The initial
term of each employment agreement extends through May 31, 2005. During 2002, Mr.
Wolf and Mr. Whitham received salaries of $381,517 and $263,869, respectively.
The agreements provide that if any payments or distributions to Mr. Wolf or Mr.
Whitham by us or any of our affiliates are subject to Section 4999 of the
Internal Revenue Code, or the Code, we are required to compensate such person
for the amount of any excise tax imposed pursuant to Section 4999 of the Code
and for any taxes imposed on that additional payment. Section 4999 of the Code
addresses additional taxes payable in the event we have a change of control.



     The employment agreements also provide for severance payments to Mr. Wolf
and Mr. Whitham if we terminate their employment other than for cause or their
employment is terminated upon a change of control, including their resignation
for good reason within one year after the occurrence of a change in control. In
such case, we must pay accrued and unpaid base salary, bonus, to the extent
earned, vested deferred compensation, any benefits then due, accrued and unpaid
vacation pay, business expenses incurred as of the date of termination and an
amount equal to three times the individual's then applicable base salary and
three times the average of the bonus he received for the last three years. In
addition, immediately prior to a change in control, all their existing options
will be immediately vested and exercisable and all restrictions with respect to
their restricted stock will lapse. 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.



RETENTION AGREEMENTS



     Following the Merger, we entered into retention agreements with our
executive officers. The retention agreements set forth the terms and conditions
of the officers' compensation in the event of termination of their employment
following a change in control, as defined in the agreements, within five years
of the date


                                        58
<PAGE>


of such retention agreements. Each agreement automatically expires if a change
in control has not occurred within the five-year period, and may be renewed for
successive one-year periods by written agreement of the parties. If a
termination following a change in control occurs within the specified period,
other than a termination for cause or without good reason, as defined in the
agreement, the terminated person will be entitled to all earned and accrued
compensation and benefits plus severance compensation equal to a stated
percentage of the sum of their respective base salary and average bonus for
three prior years, plus the amount of any excise tax imposed on such severance
payment under Section 4999 of the Code. In addition, all equity incentive awards
become immediately vested.



THE RETENTION AND SEVERANCE PLAN



     Under the Retention and Severance Plan adopted by Belco prior to the
Merger, we are obligated to pay certain benefits to former employees of Belco.
The Retention and Severance Plan generally provides that each former Belco
employee is entitled to receive a lump sum retention payment equal to 30% of
such employee's aggregate wages earned during a retention period lasting from
June 8, 2001 until the earlier of (1) 90 days after the effective date of the
Merger or (2) the termination of the merger agreement relating to the Merger. As
required by the plan's terms, we paid retention payments within 30 days of the
end of the retention period. The Retention and Severance Plan also generally
provides for severance benefits to be paid to former Belco employees whose
employment is terminated for any reason other than "cause" during the period
from June 8, 2001 through the earlier of (1) 18 months after the effective date
of the Merger or (2) the termination of the merger agreement. The severance
compensation payable under the Retention and Severance Plan is as follows:



<Table>
<Caption>
TITLE                                                 AMOUNT OF PAYMENT(1)
-----                                                 --------------------
<S>                                         <C>
Senior Vice President or higher..........   Three months' salary per year of service
                                            with a maximum payment of 18 months'
                                            salary
Vice President...........................   Two months' salary per year of service
                                            with a maximum payment of 12 months'
                                            salary
All other employees......................   One months' salary per year of service
                                            with a maximum payment of 6 months'
                                            salary
</Table>


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


(1) Minimum severance compensation for any eligible employee will be two months'
    salary.



     Severed employees eligible for severance benefits under the Retention and
Severance Plan may also be eligible for certain health insurance benefits.
Compensation payable under the Retention and Severance Plan is subject to
applicable withholding taxes and is not eligible for 401(k) matching benefits.
As of March 31, 2003, our severance obligations to all of the former Belco
employees, except Dominick Golio, were satisfied. We have subsequently paid all
of the remaining severance benefits to Mr. Golio (paid in equal installments on
a semi-monthly basis) and as of September 15, 2003, have no additional
obligations under the Retention and Severance Plan.



ITEM 11.  EXECUTIVE COMPENSATION


     The information called for by Item 11 of this report is incorporated by
reference from the section entitled "Executive Compensation" of our definitive
Proxy Statement filed with the SEC pursuant to Regulation 14A under the Exchange
Act on April 21, 2003.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information called for by Item 12 of this report is incorporated by
reference from the section entitled "Security Ownership of Certain Beneficial
Owners and Management" of our definitive Proxy Statement filed with the SEC
pursuant to Regulation 14A under the Exchange Act on April 21, 2003.

                                        59
<PAGE>

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS


                       TRANSACTIONS WITH RELATED PARTIES



SHAREHOLDERS AGREEMENT



     On February 14, 2003, Westport entered into the shareholders agreement with
WELLC, Medicor, ERI and the Belfer Group. The shareholders agreement amended and
restated the previous shareholders agreement, dated as of July 20, 2001, in
connection with WELLC's transfer of a portion of its Westport common stock to
Medicor. Medicor and WELLC are collectively referred to as the Medicor Group.
The shareholders agreement contained provisions that determined how the Medicor
Group, ERI and the Belfer Group voted their respective shares of Westport common
stock and that, among other things, had the effect, based on their share
ownership, of giving these parties the ability to determine the composition of
our board of directors and otherwise affect our corporate governance and
business activities, including provisions whereby:



     - The Medicor Group, ERI and the Belfer Group were obligated to vote their
       shares according to and consistent with the terms of the shareholders
       agreement;



     - Westport, the Medicor Group, ERI and the Belfer Group were obligated to
       take or cause to be taken all lawful action necessary to ensure that our
       articles of incorporation and bylaws were at all times consistent with
       the provisions of the shareholders agreement;



     - Our Board of Directors was required to be comprised of 11 directors, two
       of whom were required to be independent directors (as such term is
       defined in the shareholders agreement) divided into three classes, with
       directors in each class having a three-year term following a transition
       period in which the initial Class 1 directors served a one-year term, the
       initial Class 2 directors served a two-year term and the initial Class 3
       directors served a three-year term;



     - Medicor and ERI each had the right to nominate one director to Class 3,
       one director to Class 2 and one director to Class 1 and the Belfer Group
       had the right to nominate one director to Class 3 and one director to
       Class 1. The number of directors any such party may nominate was reduced
       if such party's ownership of our common stock fell below specified
       percentages of the total number of shares of our common stock then
       outstanding;



     - Medicor, ERI and the Belfer Group, respectively, each had the right (1)
       subject to applicable law, to remove, with or without cause, any director
       nominated in accordance with the terms of the shareholders agreement by
       Medicor, ERI or the Belfer Group, respectively, and (2) to nominate any
       replacement for a director nominated in accordance with the terms of the
       new shareholders agreement by Medicor, ERI or the Belfer Group,
       respectively, upon the death, resignation, retirement, disqualification
       or removal from office of such director. Our Board of Directors was
       required to duly appoint as a director each person so nominated to fill a
       vacancy on the board of directors. Notwithstanding the foregoing,
       pursuant to Nevada law, an incumbent director could not be removed from
       office except upon the affirmative vote of at least two-thirds of the
       issued and outstanding voting power;



     - We could take and could permit our subsidiaries to take and engage in the
       following actions only upon receiving supermajority approval (as such
       term is defined in the shareholders agreement) of our Board of Directors:



       - Acquisition of Stock.  Subject to certain conditions, neither ERI, the
         Medicor Group nor the Belfer Group were able to acquire any additional
         shares of our common stock without the consent of the other parties;



       - Issuance of Common Stock.  Issue, sell, grant or award or enter into
         any agreement to issue, sell, grant or award any of our common stock
         other than (1) pursuant to agreements or obligations in existence as of
         the effective time of the shareholders agreement, (2) the issuance


                                        60
<PAGE>


        of our common stock pursuant to any rights or agreements including
        without limitation any security convertible or exchangeable into or
        exercisable for, with or without consideration, our common stock so long
        as such rights or agreements received supermajority approval and (3) the
        grant of options and the issuance of restricted stock under our stock
        incentive plans for the benefit of our employees and directors and the
        issuance of our common stock upon the exercise of such options;



      - Debt to Total Capitalization.  Incur funded debt of Westport and our
        subsidiaries so that the ratio of debt of Westport and our subsidiaries
        to total capitalization was greater than 0.4 to 1.0; and



      - Sale Transactions.  Enter into any merger or consolidation, sale of all
        or substantially all of our assets or sale of assets or transfer to a
        third party by sale of assets, merger or otherwise by Westport or any of
        our subsidiaries (in one transaction or a series of related
        transactions) of any subsidiary or the assets or business of Westport or
        a subsidiary thereof which involved more than $150 million (or such
        other amount, established by resolution of our Board of Directors
        (approved by supermajority approval) from time to time), of our total
        assets and our subsidiaries taken as a whole, including a sale of
        Westport effected by means of a sale of our common stock, but excluding,
        however, dispositions of assets in the ordinary course of business
        (including, but not limited to, oil and natural gas production);



     - each of the Medicor Group, ERI and the Belfer Group was granted unlimited
       piggyback registration rights;



     - each of the Medicor Group and ERI was granted three demand registration
       rights and the Belfer Group was granted two demand registration rights;
       and



     - each of the Medicor Group, ERI and the Belfer Group were obligated to
       enter into holdback agreements if requested by the underwriters in
       underwritten offerings.



     On October 1, 2003, Westport, Medicor, WELLC, ERI and the Belfer Group
entered into the termination and voting agreement and Westport, Medicor, WELLC,
ERI and certain members of the Belfer Group, also referred to as the New Belfer
Group, entered into the registration rights agreement, in each case effective as
of October 1, 2003. The termination and voting agreement terminates the
shareholders agreement and includes the following agreements:



     - Each of the Medicor Group, EQT Investments, Inc., a successor to ERI,
       also referred to as EQT, and the New Belfer Group have the right to
       nominate one director at the 2004 annual meeting of Westport's
       stockholders; and



     - Medicor, EQT and the New Belfer Group, respectively, each have the right
       (1) subject to applicable law, to remove, with or without cause, a
       director nominated in accordance with the terms of the termination and
       voting agreement by Medicor, EQT or the New Belfer Group, respectively,
       and (2) to nominate any replacement for such director upon his or her
       death, resignation, retirement, disqualification or removal from office.
       Our Board of Directors is obligated to duly appoint as a director each
       person so nominated to fill a vacancy on the Board of Directors.
       Notwithstanding the foregoing, pursuant to Nevada law, an incumbent
       director may not be removed from office except upon the affirmative vote
       of at least two-thirds of the issued and outstanding voting power.



Pursuant to the registration rights agreement:



     - each of the Medicor Group, EQT and the New Belfer Group is granted
       unlimited piggyback registration rights;



     - each of the Medicor Group, EQT and the New Belfer Group is granted a
       limited number of demand registration rights; and


                                        61
<PAGE>


     - each of the Medicor Group, EQT and the New Belfer Group are obligated to
       enter into holdback agreements if requested by the underwriters in
       underwritten offerings.



OFFICE LEASE



     Belco paid Robert A. Belfer, former Chairman of the Board and Chief
Executive Officer of Belco and one of our directors, a fee of $172,172 during
2001 for office space and services provided through such office from January
2001 through August 2001. After our merger with and into Belco, Westport paid a
fee of $88,908 to Mr. Belfer for the office space from September 2001 through
January 2002. The fee is based on the actual cost of such office space pro-rated
to the amount utilized in our operations. We believe the fee compared favorably
to the terms which might have been available from a non-affiliated party. We
have not paid a fee to Mr. Belfer for office space since January 31, 2002 and do
not intend to use this office space in the future.



DOMINICK GOLIO



     Pursuant to current federal income tax laws, recipients of awards of
restricted stock under Belco's 1996 Stock Incentive Plan are deemed to have
income equal to the fair market value of the vested shares of our common stock
on the date of vesting. As of December 31, 2001, Dominick J. Golio was indebted
to us in the amount of $69,320, representing federal income taxes paid by us on
behalf of Dominick J. Golio that arose pursuant to the vesting of Mr. Golio's
restricted stock. Upon Mr. Golio's termination in March 2002, the amount of his
indebtedness to us was satisfied in full out of his severance compensation. We
did not charge interest on this indebtedness.



     In October 2001, we entered into a letter agreement with Dominick J. Golio
whereby Mr. Golio would, after cessation of his employment, continue to assist
us in certain pending litigation. As compensation, we agreed to pay Mr. Golio
7 1/2% of our total net recovery, if any, in the litigation. The suit was
settled in September 2002. On December 16, 2002, Mr. Golio received a cash
payment of $156,334 and agreed to receive severance benefits with an aggregate
cash value of $58,936 in full satisfaction of the amounts owed to him under the
letter agreement. In addition to our obligations to Mr. Golio under the letter
agreement, we are obligated to pay severance benefits in the amount of $78,564
to Mr. Golio under Belco's Retention and Severance Plan by September 15, 2003.
As of September 15, 2003, we have paid all of the amounts owed to Mr. Golio
under the letter agreement and Belco's Retention and Severance Plan and have no
additional obligations to Mr. Golio.



ITEM 14.  CONTROLS AND PROCEDURES


     Our Chairman of the Board and Chief Executive Officer and our Chief
Financial Officer (our principal executive officer and principal financial
officer, respectively) have concluded, based on their evaluation as of a date
within 90 days prior to the date of the filing of this annual report on Form
10-K, that our disclosure controls and procedures are effective to ensure that
information required to be disclosed by us in the reports filed or submitted by
us under the Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms, and include controls and procedures designed to ensure
that information required to be disclosed by us in such reports is accumulated
and communicated to our management, including our Chairman of the Board and
Chief Executive Officer and our Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure.

     There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
such evaluation.

                                        62
<PAGE>

                                    PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     (a) The following documents are filed as part of this report:

          1. Financial Statements: See Index to Consolidated Financial
     Statements and Schedules immediately following the signature page of this
     report.

          2. Financial Statement Schedules: See Index to Consolidated Financial
     Statements and Schedules immediately following the signature page of this
     report.

          3. Exhibits: The following documents are filed as exhibits to this
     report:


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
    1.1       --    Purchase Agreement, dated as of March 27, 2003, by and among
                    Westport, subsidiary guarantors party thereto and Lehman
                    Brothers Inc. (incorporated by reference to Exhibit 1 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-105834), filed with the SEC on June 4, 2003).
    1.2       --    Stock Purchase Agreement, dated as of November 15, 2002, by
                    and among Westport, Spindrift Partners, L.P., Spindrift
                    Investors (Bermuda) L.P., Global Natural Resources III and
                    Global Natural Resources III L.P. (incorporated by reference
                    to Exhibit 1 to Westport's Registration Statement on Form
                    S-3 (Registration No. 333-102281), filed with the SEC on
                    December 31, 2002).
    2.1       --    Agreement and Plan of Merger, dated as of March 9, 2000, by
                    and among Westport Oil and Gas Company, Inc., Westport
                    Energy Corporation, Equitable Production Company, Equitable
                    Production (Gulf) Company and EPGC Merger Sub Corporation
                    (incorporated by reference to Exhibit 2.1 to the
                    Registration Statement on Form S-1 of Westport Resources
                    Corporation, a Delaware corporation (Registration No.
                    333-40422), filed with the SEC on June 29, 2000).
    2.2       --    Agreement and Plan of Merger, dated as of June 8, 2001,
                    among Belco and Westport Resources Corporation, a Delaware
                    corporation (incorporated by reference to Exhibit 2.1 to
                    Belco's Registration Statement on Form S-4/A (Registration
                    No. 333-64320), filed with the SEC on July 24, 2001).
    2.3       --    Purchase and Sale Agreement, dated November 6, 2002, among
                    Westport and certain affiliates of El Paso Corporation
                    parties thereto (incorporated by reference to Exhibit 2 to
                    Westport's Current Report on Form 8-K/A, filed with the SEC
                    on December 27, 2002).
    3.1       --    Amended Articles of Incorporation of Westport (incorporated
                    by reference to Exhibit 3.1 to Westport's Registration
                    Statement on Form 8-A/A, filed with the SEC on August 31,
                    2001).
    3.2       --    Certificate of Amendment to Amended Articles of
                    Incorporation of Westport, dated March 5, 2003 (incorporated
                    by reference to Exhibit 3.2 to Westport's Quarterly Report
                    on Form 10-Q for the quarter ended March 31, 2003, filed on
                    May 8, 2003).
    3.3       --    Third Amended and Restated Bylaws of Westport effective as
                    of October 1, 2003 (incorporated by reference to Exhibit 3.3
                    to Westport's Quarterly Report on form 10-Q for the quarter
                    ended September 30, 2003, filed with the SEC on November 14,
                    2003).
    4.1       --    Specimen Certificate for shares of Common Stock of Westport
                    (incorporated by reference to Exhibit 4.1 to Westport's
                    Registration Statement on Form 8-A/A, filed with the SEC on
                    August 31, 2001).
    4.2       --    Specimen Certificate for shares of 6 1/2% Convertible
                    Preferred Stock of Westport (incorporated by reference to
                    Exhibit 4 to Westport's Registration Statement on
                    Form 8-A/A, filed with the SEC on August 31, 2001).
  **4.3       --    Third Amended and Restated Shareholders Agreement dated
                    February 14, 2003 among Westport, ERI, Medicor Foundation,
                    WELLC and certain stockholders named therein.
</Table>


                                        63
<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
    4.4       --    Termination and Voting Agreement, dated as of October 1,
                    2003, among Westport, ERI, WELLC, Medicor and certain
                    stockholders named therein (incorporated by reference to
                    Exhibit 4.5 to Westport's Quarterly Report on Form 10-Q for
                    the quarter ended September 30, 2003, filed with the SEC on
                    November 14, 2003).
    4.5       --    Registration Rights Agreement, dated as of October 1, 2003,
                    among Westport, ERI, WELLC, Medicor and certain stockholders
                    named therein (incorporated by reference to Exhibit 4.6 to
                    Westport's Quarterly Report on Form 10-Q for the quarter
                    ended September 30, 2003, filed with the SEC on November 14,
                    2003).
    4.6       --    Registration Rights Agreement, dated as of April 3, 2003,
                    among Westport, subsidiary guarantors party thereto and
                    Lehman Brothers Inc. (incorporated by reference to Exhibit
                    4.7 to Westport's Registration Statement on Form S-4
                    (Registration No. 333-105834), filed with the SEC on June 4,
                    2003).
    4.7       --    Indenture, dated as of November 5, 2001, among Westport,
                    subsidiary guarantors from time to time party thereto and
                    The Bank of New York, as trustee (incorporated by reference
                    to Exhibit 4.4 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-77060), filed with the SEC on
                    January 18, 2002).
    4.8       --    First Supplemental Indenture, dated as of December 31, 2001,
                    among Westport, existing subsidiary guarantors party
                    thereto, new subsidiary guarantors named therein and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.5 to Westport's Registration Statement on Form S-4
                    (Registration No. 333-77060), filed with the SEC on January
                    18, 2002).
    4.9       --    Second Supplemental Indenture, dated as of December 17,
                    2002, among Westport, existing subsidiary guarantors party
                    thereto, new subsidiary guarantors named therein and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.9 to Westport's Registration Statement on Form S-4
                    (Registration No. 333-102705), filed with the SEC on January
                    24, 2003).
    4.10      --    Third Supplemental Indenture, dated as of April 3, 2003,
                    among Westport, subsidiary guarantors party thereto and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.11 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-105834), filed on June 4, 2003).
    4.11      --    Indenture, dated as of September 23, 1997, among Belco, as
                    issuer, and The Bank of New York, as trustee (incorporated
                    by reference to Exhibit 4.1 of Belco's Registration
                    Statement on Form S-4 (Registration No. 333-37125), filed
                    with the SEC on February 6, 1996).
    4.12      --    Supplemental Indenture dated as of February 25, 1998 between
                    Coda Energy, Inc., Diamond Energy Operating Company, Electra
                    Resources, Inc., Belco Operating Corp., Belco Energy L.P.,
                    Gin Lane Company, Fortune Corp., BOG Wyoming LLC and Belco
                    Finance Co. (individually, the Subsidiary Guarantors), a
                    subsidiary of Belco, and The Bank of New York, a New York
                    banking corporation (as Trustee) amending the Indenture
                    filed as Exhibit 4.2 above (incorporated by reference to
                    Exhibit 4.3 of Belco's Annual Report on Form 10-K for the
                    fiscal year ended December 31, 1997, filed with the SEC on
                    March 26, 1998).
    4.13      --    Second Supplemental Indenture, dated as of August 21, 2001,
                    among Westport, certain subsidiary guarantors party thereto
                    and The Bank of New York, as trustee (incorporated by
                    reference to Exhibit 4.3 to Westport's Quarterly Report on
                    Form 10-Q for the quarter ended September 30, 2001, filed
                    with the SEC on November 14, 2001).
    4.14      --    Third Supplemental Indenture, dated as of December 31, 2001,
                    among Westport, existing subsidiary guarantors party
                    thereto, new subsidiary guarantors named therein and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.10 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-77060), filed with the SEC on
                    January 18, 2002).
</Table>


                                        64
<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
    4.15      --    Fourth Supplemental Indenture, dated as of December 17,
                    2002, among Westport, existing subsidiary guarantors, new
                    subsidiary guarantors and The Bank of New York, as trustee
                    (incorporated by reference to Exhibit 4.14 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-102705), filed with the SEC on January 24, 2003).
    4.16      --    Certificate of Designations of 6 1/2% Convertible Preferred
                    Stock dated March 5, 1998 (incorporated by reference to
                    Exhibit 4.1 of Belco's Current Report on Form 8-K, filed on
                    March 11, 1998).
    4.17      --    Form of 8 1/4% Note (contained in the Indenture listed as
                    Exhibit 4.4 above) (incorporated by reference to Exhibit 4.4
                    to Westport's Registration Statement on Form S-4
                    (Registration No. 333-77060), filed with the SEC on January
                    18, 2002).
    4.18      --    Form of 8 7/8% Note (contained in the Indenture listed as
                    Exhibit 4.8 above) (incorporated by reference to Exhibit 4.1
                    to Belco's Registration Statement on Form S-4 (Registration
                    No. 333-37125), filed with the SEC on February 6, 1996).
    4.19      --    Form of Indenture for Senior Debt Securities (incorporated
                    by reference to Exhibit 4.1 to Belco's Amendment No. 1 to
                    the Registration Statement on Form S-3 (Registration No.
                    333-42107), filed with the SEC on December 23, 1997).
    4.20      --    Form of Indenture for Subordinated Debt Securities
                    (incorporated by reference to Exhibit 4.2 to Belco's
                    Amendment No. 1 to the Registration Statement on Form S-3
                    (Registration No. 333-42107), filed with the SEC on December
                    23, 1997).
   10.1       --    Credit Agreement, dated as of December 17, 2002, among
                    Westport, certain lenders from time to time party thereto,
                    Credit Suisse First Boston Corporation, as syndication
                    agent, JPMorgan Chase Bank, as administrative agent and
                    issuing bank, certain documentation agents party thereto,
                    Wachovia Bank, N.A., as senior managing agent, and certain
                    managing agents named therein (incorporated by reference to
                    Exhibit 10.1 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-102705), filed with the SEC on
                    January 24, 2003).
   10.2       --    First Amendment to Credit Agreement, dated as of October 15,
                    2003, among Westport, subsidiary guarantors party thereto,
                    JP Morgan Chase Bank, as administrative agent, and certain
                    lenders named therein (incorporated by reference to Exhibit
                    10.1 to Westport's Quarterly Report on Form 10-Q for the
                    quarter ended September 30, 2003, filed with the SEC on
                    November 14, 2003).
   10.3       --    Subsidiary Guarantee, dated as of December 17, 2002, by each
                    subsidiary guarantor party thereto in favor of JPMorgan
                    Chase Bank, as administrative agent for certain lenders and
                    creditors (incorporated by reference to Exhibit 10.2 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-102705), filed with the SEC on January 24, 2003).
   10.4       --    Westport Resources Corporation 2000 Stock Incentive Plan, as
                    amended on August 21, 2001 (incorporated by reference to
                    Exhibit 4.4 to Westport's Registration Statement on Form
                    S-8, filed with the SEC on August 31, 2001).
   10.5       --    Westport Resources Corporation Annual Incentive Plan 2000
                    (incorporated by reference to Exhibit 10.6 to Old Westport's
                    Registration Statement on Form S-1 (Registration No.
                    333-40422), filed with the SEC on June 29, 2000).
   10.6       --    Employment Agreement, effective as of April 1, 2002, between
                    Westport and Donald D. Wolf (incorporated by reference to
                    Exhibit 10.1 to Westport's Quarterly Report on Form 10-Q for
                    the quarter ended March 31, 2002, filed with the SEC on May
                    13, 2002).
   10.7       --    Employment Agreement, effective as of April 1, 2002, between
                    Westport and Barth E. Whitham (incorporated by reference to
                    Exhibit 10.2 to Westport's Quarterly Report on Form 10-Q for
                    the quarter ended March 31, 2002, filed with the SEC on May
                    13, 2002).
   10.8       --    Form of Indemnification Agreement between Westport and its
                    officers and directors (incorporated by reference to Exhibit
                    10.1 to Westport's Quarterly Report on Form 10-Q for the
                    quarter ended June 30, 2002, filed with the SEC on August
                    14, 2002).
</Table>


                                        65
<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
   10.9       --    Belco Oil & Gas Corp. 1996 Nonemployee Directors' Stock
                    Option Plan (incorporated by reference to Exhibit 10.1 of
                    Belco's Registration Statement on Form S-1 (Registration No.
                    333-1034), filed with the SEC on February 6, 1996).
   10.10      --    First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee
                    Directors' Stock Option Plan (incorporated by reference to
                    Exhibit 10.1 of Belco's Quarterly Report on Form 10-Q for
                    the quarter ended June 30, 1999, filed with the SEC on
                    August 13, 1999).
   10.11      --    Belco Oil & Gas Corp. 1996 Stock Incentive Plan
                    (incorporated by reference to Exhibit 10.2 of Belco's
                    Registration Statement on Form S-1 (Registration No.
                    333-1034), filed with the SEC on February 6, 1996).
   10.12      --    First Amendment to Belco Oil & Gas Corp. 1996 Stock
                    Incentive Plan (incorporated by reference to Exhibit 10.2 of
                    Belco's Quarterly Report on Form 10-Q for the quarter ended
                    June 30, 2000, filed with the SEC on August 14, 2000).
   10.13      --    Form of Indemnification Agreement between Belco and its
                    officers and directors (incorporated by reference to Exhibit
                    10.6 of Belco's Registration Statement on Form S-1
                    (Registration No. 333-1034), filed with the SEC on February
                    6, 1996).
   10.14      --    Belco Oil & Gas Corp. Retention and Severance Benefit Plan
                    dated June 8, 2001 (incorporated by reference to Exhibit
                    10.18 to Belco's Registration Statement on Form S-4/A
                    (Registration No. 333-64320), filed with the SEC on July 24,
                    2001).
   10.15      --    Amended and Restated Well Participation Letter Agreement
                    dated as of December 31, 1992 between Chesapeake Operating,
                    Inc. and Belco, as amended by (i) Letter Agreement dated
                    April 14, 1983, (ii) Amendment dated December 31, 1993, and
                    (iii) Third Amendment dated December 30, 1994 (incorporated
                    by reference to Exhibit 10.7 of Belco's Registration
                    Statement on Form S-1 (Registration No. 333-1034), filed
                    with the SEC on February 6, 1996).
   10.16      --    Sale Agreement (Independence) dated as of June 10, 1994
                    between Chesapeake Operating, Inc. and Belco (incorporated
                    by reference to Exhibit 10.10 of Belco's Registration
                    Statement on Form S-1 (Registration No. 333-1034), filed
                    with the SEC on February 6, 1996).
   10.17      --    Sale and Area of Mutual Interest Agreement (Greater
                    Giddings) dated as of December 30, 1994 between Chesapeake
                    Operating, Inc. and Belco (incorporated by reference to
                    Exhibit 10.12 of Belco's Registration Statement on Form S-1
                    (Registration No. 333-1034), filed with the SEC on February
                    6, 1996).
   10.18      --    Golden Trend Area of Mutual Interest Agreement dated as of
                    December 17, 1992 between Chesapeake Operating, Inc. and
                    Belco (incorporated by reference to Exhibit 10.13 of Belco's
                    Registration Statement on Form S-1 (Registration No.
                    333-1034), filed with the SEC on February 6, 1996).
   10.19      --    Form of Participation Agreement for Belco Oil & Gas Corp.
                    1992 Moxa Arch Drilling Program (incorporated by reference
                    to Exhibit 10.15 of Belco's Registration Statement on Form
                    S-1 (Registration No. 333-1034), filed with the SEC on
                    February 6, 1996).
   10.20      --    Form of Offset Participation Agreement to the Moxa Arch 1992
                    Offset Drilling Program (incorporated by reference to
                    Exhibit 10.16 of Belco's Registration Statement on Form S-1
                    (Registration No. 333-1034), filed with the SEC on February
                    6, 1996).
   10.21      --    Form of Participation Agreement for Belco Oil & Gas Corp.
                    1993 Moxa Arch Drilling Program (incorporated by reference
                    to Exhibit 10.17 of Belco's Registration Statement on Form
                    S-1 (Registration No. 333-1034), filed with the SEC on
                    February 6, 1996).
   10.22      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Grant W. Henderson
                    (incorporated by reference to Exhibit 10.24 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.23      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Lon McCain
                    (incorporated by reference to Exhibit 10.25 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
</Table>


                                        66
<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
   10.24      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Kenneth D.
                    Anderson (incorporated by reference to Exhibit 10.26 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-77060), filed with the SEC on January 18, 2002).
   10.25      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Lynn S. Belcher
                    (incorporated by reference to Exhibit 10.27 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.26      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Brian K. Bess
                    (incorporated by reference to Exhibit 10.28 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.27      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Howard L. Boigon
                    (incorporated by reference to Exhibit 10.29 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.28      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Robert R. McBride,
                    Jr. (incorporated by reference to Exhibit 10.30 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-77060), filed with the SEC on January 18, 2002).
 **10.29      --    Change in Control Severance Protection Agreement, dated as
                    of February 1, 2003, between Westport and Carter Mathies.
   10.30      --    Change in Control Severance Protection Agreement, effective
                    as of June 1, 2003, between Westport and Peter M. Mueller
                    (incorporated by reference to Exhibit 10.1 to Westport's
                    Quarterly Report on Form 10-Q for the quarter ended June 30,
                    2003 filed with the SEC on August 14, 2003).
   21         --    List of Subsidiaries of Westport (incorporated by reference
                    to Exhibit 21 Westport's Registration Statement on Form S-4
                    (Registration No. 333-102705), filed with the SEC on January
                    24, 2003).
  *23.1       --    Consent of Independent Public Accountants, KPMG, LLP.
  *23.2       --    Consent of Ryder Scott Company.
  *23.3       --    Consent of Netherland, Sewell & Associates, Inc.
 **24.1       --    Power of Attorney.
  *31.1       --    Certification pursuant to Section 302 of the Sarbanes-Oxley
                    Act of 2002 of Chief Executive Officer of Westport.
  *31.2       --    Certification pursuant to Section 302 of the Sarbanes-Oxley
                    Act of 2002 of Chief Financial Officer of Westport.
  *32.1       --    Certification pursuant to Section 906 of the Sarbanes-Oxley
                    Act of 2002 of Chief Executive Officer of Westport.
  *32.2       --    Certification pursuant to Section 906 of the Sarbanes-Oxley
                    Act of 2002 of Chief Financial Officer of Westport.
</Table>


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

 * Filed herewith.

** Previously filed.

     Certain of the exhibits to this filing contain schedules which have been
omitted in accordance with applicable regulations. Westport undertakes to
furnish supplementally a copy of any omitted schedule to the Securities and
Exchange Commission upon request.

                                        67
<PAGE>

     (b) Reports on Form 8-K.

     - Current Report on Form 8-K (Item 5) filed on November 7, 2002 by
       Westport;

     - Current Report on Form 8-K (Item 9) filed on December 2, 2002 by
       Westport;

     - Current Report on Form 8-K (Item 9) filed on December 2, 2002 by
       Westport;

     - Current Report on Form 8-K (Item 5) filed on December 2, 2002 by
       Westport;

     - Current Report on Form 8-K (Items 5 and 7) filed on December 2, 2002 by
       Westport, as amended by the Current Report on Form 8-K/A (Items 5 and 7)
       as filed with the SEC on December 12, 2002, as further amended by the
       Current Report on Form 8-K/A (Items 2 and 7) as filed with the SEC on
       December 27, 2002 and by the Current Report on Form 8-K/A (Items 5 and 7)
       as filed with the SEC on February 26, 2003; and

     - Current Report on Form 8-K (Item 5) filed on December 12, 2002 by
       Westport.

                                        68
<PAGE>

                                   SIGNATURES

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


Date: February 5, 2004


                                          WESTPORT RESOURCES CORPORATION

                                          By:      /s/ DONALD D. WOLF
                                            ------------------------------------
                                              Name:  Donald D. Wolf
                                              Title: Chairman of the Board and
                                                     Chief Executive Officer


     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons in the capacities indicated on
February 5, 2004:



<Table>
<Caption>
                     SIGNATURE                                          TITLE
                     ---------                                          -----
<S>      <C>                                          <C>

                /s/ DONALD D. WOLF                      Chairman of the Board, Chief Executive
---------------------------------------------------   Officer (Principal Executive Officer) and
                  Donald D. Wolf                                       Director


                  /s/ LON MCCAIN                       Vice President, Chief Financial Officer
---------------------------------------------------       and Treasurer (Principal Financial
                    Lon McCain                                         Officer)


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


               /s/ MICHAEL L. BEATTY                                   Director
---------------------------------------------------
                 Michael L. Beatty


                         *                                             Director
---------------------------------------------------
                Laurence D. Belfer


                /s/ RICHARD D. DOLE                                    Director
---------------------------------------------------
                  Richard D. Dole


                         *                                             Director
---------------------------------------------------
                   James M. Funk


                         *                                             Director
---------------------------------------------------
                  David L. Porges


                         *                                             Director
---------------------------------------------------
                  Michael Russell


               /s/ ROBERT F. SEMMENS                                   Director
---------------------------------------------------
                 Robert F. Semmens


                         *                                             Director
---------------------------------------------------
                    Randy Stein
</Table>


                                        69
<PAGE>

<Table>
<Caption>
                     SIGNATURE                                          TITLE
                     ---------                                          -----

<S>      <C>                                          <C>

                         *                                             Director
---------------------------------------------------
                William F. Wallace


 *By:                /s/ DONALD D. WOLF
         ------------------------------------------
                       Donald D. Wolf
                      Attorney-in-Fact
</Table>

                                        70
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


<Table>
<S>                                                            <C>
Reports of Independent Public Accountants...................   F-3
Consolidated Balance Sheets as of December 31, 2002 and
  2001......................................................   F-4
Consolidated Statements of Operations for the years ended
  December 31, 2002, 2001 and 2000..........................   F-5
Consolidated Statements of Stockholders' Equity for the
  years ended December 31, 2002, 2001 and 2000..............   F-6
Consolidated Statements of Cash Flows for the years ended
  December 31, 2002, 2001 and 2000..........................   F-7
Notes to Consolidated Financial Statements..................   F-8
</Table>


                                       F-1
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

The Board of Directors
Westport Resources Corporation:

     We have audited the 2002 consolidated financial statements of Westport
Resources Corporation (a Nevada corporation) and subsidiaries as listed in the
accompanying index. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audit. The 2001
and 2000 consolidated financial statements of Westport Resources Corporation and
subsidiaries as listed in the accompanying index were audited by other auditors
who have ceased operations. Those auditors' report, dated March 1, 2002, on
those consolidated financial statements was unqualified and included an
explanatory paragraph that described the change in the Company's method of
accounting for derivative instruments and hedging activities discussed in Notes
1 and 3 to the consolidated financial statements.

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

     In our opinion, the 2002 consolidated financial statements referred to
above present fairly, in all material respects, the financial position of
Westport Resources Corporation and subsidiaries as of December 31, 2002, and the
results of its operations and its cash flows for the year then ended in
conformity with accounting principles generally accepted in the United States of
America.

     As discussed in Notes 1 and 3 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and hedging
activities in 2001.

                                          /s/  KPMG LLP

Denver, Colorado
February 21, 2003

                                       F-2
<PAGE>

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

     THE FOLLOWING REPORT IS A COPY OF THE PREVIOUSLY ISSUED REPORT FROM ARTHUR
ANDERSEN LLP (ANDERSEN). ANDERSEN DID NOT PERFORM ANY PROCEDURES IN CONNECTION
WITH THIS ANNUAL REPORT ON FORM 10-K. ACCORDINGLY, THIS REPORT HAS NOT BEEN
REISSUED BY ANDERSEN.

To Westport Resources Corporation:

     We have audited the accompanying consolidated balance sheets of Westport
Resources Corporation (a Nevada corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. 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 Resources
Corporation and subsidiaries as of December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

     As explained in Notes 1 and 4 to the consolidated financial statements, on
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities.

                                          ARTHUR ANDERSEN LLP

Denver, Colorado
March 1, 2002

                                       F-3
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 2002         2001
                                                              ----------   ----------
                                                                  (IN THOUSANDS,
                                                                EXCEPT SHARE DATA)
<S>                                                           <C>          <C>
                                       ASSETS
Current assets:
  Cash and cash equivalents.................................  $   42,761   $   27,584
  Accounts receivable, net..................................      73,549       61,808
  Derivative assets.........................................      14,861        7,832
  Prepaid expenses and other assets.........................      13,358        5,474
                                                              ----------   ----------
         Total current assets...............................     144,529      102,698
                                                              ----------   ----------
Property and equipment, at cost:
  Oil and natural gas properties, successful efforts method:
    Proved properties.......................................   2,177,656    1,446,331
    Unproved properties.....................................     104,430      105,539
                                                              ----------   ----------
                                                               2,282,086    1,551,870
  Less accumulated depletion, depreciation and
    amortization............................................    (481,396)    (280,737)
                                                              ----------   ----------
         Net oil and gas properties.........................   1,800,690    1,271,133
                                                              ----------   ----------
  Building and other office furniture and equipment.........       9,686        8,099
  Less accumulated depreciation.............................      (3,933)      (3,028)
                                                              ----------   ----------
         Net building and other office furniture and
           equipment........................................       5,753        5,071
                                                              ----------   ----------
Other assets:
  Long-term derivative assets...............................      14,824          612
  Goodwill..................................................     246,712      214,844
  Other assets..............................................      21,033        9,858
                                                              ----------   ----------
         Total other assets.................................     282,569      225,314
                                                              ----------   ----------
         Total assets.......................................  $2,233,541   $1,604,216
                                                              ==========   ==========
                        LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable..........................................  $   51,158   $   47,901
  Accrued expenses..........................................      39,209       30,294
  Ad valorem taxes payable..................................       8,988        6,930
  Derivative liabilities....................................      56,156        3,289
  Income taxes payable......................................          86          550
  Other current liabilities.................................          --          369
                                                              ----------   ----------
         Total current liabilities..........................     155,597       89,333
Long-term debt..............................................     799,358      429,224
Deferred income taxes.......................................     124,530      158,005
Long-term derivative liabilities............................      21,305        5,956
Other liabilities...........................................         745        1,402
                                                              ----------   ----------
         Total liabilities..................................   1,101,535      683,920
                                                              ----------   ----------
Commitments and contingencies (Note 12)
Stockholders' equity:
  6 1/2% Convertible preferred stock, $.01 par value;
    10,000,000 shares authorized; 2,930,000 issued and
    outstanding at December 31, 2002 and 2001,
    respectively............................................          29           29
  Common stock, $.01 par value; 70,000,000 shares
    authorized; 66,823,830 and 52,092,691 shares issued and
    outstanding at December 31, 2002 and 2001,
    respectively............................................         668          521
  Additional paid-in capital................................   1,150,345      877,960
  Treasury stock -- at cost; 33,617 and 30,000 shares at
    December 31, 2002 and 2001, respectively................        (469)        (408)
  Retained earnings.........................................           2       33,330
  Accumulated other comprehensive income (loss):
    Deferred hedge loss, net................................     (18,408)       8,864
    Cumulative translation adjustment.......................        (161)          --
                                                              ----------   ----------
         Total stockholders' equity.........................   1,132,006      920,296
                                                              ----------   ----------
         Total liabilities and stockholders' equity.........  $2,233,541   $1,604,216
                                                              ==========   ==========
</Table>

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

                                       F-4
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS


<Table>
<Caption>
                                                               FOR THE YEAR ENDED DECEMBER 31,
                                                              ---------------------------------
                                                                2002        2001        2000
                                                              ---------   ---------   ---------
                                                                       (IN THOUSANDS,
                                                                  EXCEPT PER SHARE AMOUNTS)
<S>                                                           <C>         <C>         <C>
Operating revenues:
  Oil and natural gas sales.................................  $428,430    $317,278    $244,669
  Hedge settlements.........................................    (1,276)      2,091     (24,627)
  Commodity price risk management activities:
    Non-hedge settlements...................................       822      15,300          --
    Non-hedge change in fair value of derivatives...........   (26,723)     14,323        (739)
  Gain (loss) on sale of operating assets, net..............    (1,685)       (132)      3,130
                                                              --------    --------    --------
      Net revenues..........................................   399,568     348,860     222,433
                                                              --------    --------    --------
Operating costs and expenses:
  Lease operating expenses..................................    89,328      55,315      34,397
  Production taxes..........................................    23,954      13,407      10,631
  Transportation costs......................................     7,961       5,157       3,034
  Exploration...............................................    32,390      31,313      12,790
  Depletion, depreciation and amortization..................   203,093     124,059      64,856
  Impairment of proved properties...........................    19,700       9,423       2,911
  Impairment of unproved properties.........................     9,961       6,974       5,124
  Stock compensation expense, net...........................     4,608         719       5,539
  General and administrative................................    23,629      17,678       7,542
                                                              --------    --------    --------
      Total operating expenses..............................   414,624     264,045     146,824
                                                              --------    --------    --------
      Operating income (loss)...............................   (15,056)     84,815      75,609
Other income (expense):
  Interest expense..........................................   (34,836)    (13,196)     (9,731)
  Interest income...........................................       546       1,668       1,230
  Change in interest rate swap fair value...................       226       4,960          --
  Other.....................................................     1,002         211         152
                                                              --------    --------    --------
Income (loss) before income taxes...........................   (48,118)     78,458      67,260
                                                              --------    --------    --------
Benefit (provision) for income taxes:
  Current...................................................     2,094      (2,006)       (675)
  Deferred..................................................    17,458     (26,631)    (23,049)
                                                              --------    --------    --------
      Total benefit (provision) for income taxes............    19,552     (28,637)    (23,724)
                                                              --------    --------    --------
Net income (loss)...........................................   (28,566)     49,821      43,536
Preferred stock dividends...................................     4,762       1,587          --
                                                              --------    --------    --------
Net income (loss) available to common stockholders..........  $(33,328)   $ 48,234    $ 43,536
                                                              ========    ========    ========
Weighted average number of common shares outstanding:
      Basic.................................................    53,007      43,408      28,296
                                                              ========    ========    ========
      Diluted...............................................    53,007      44,168      28,645
                                                              ========    ========    ========
Net income (loss) per common share:
      Basic.................................................  $  (0.63)   $   1.11    $   1.54
                                                              ========    ========    ========
      Diluted...............................................  $  (0.63)   $   1.09    $   1.52
                                                              ========    ========    ========
</Table>


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

                                       F-5
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<Table>
<Caption>
                                                                                         TREASURY
                                     PREFERRED STOCK    COMMON STOCK     ADDITIONAL    COMMON STOCK     RETAINED EARNINGS
                                     ---------------   ---------------    PAID-IN     ---------------     (ACCUMULATED
                                     SHARES   AMOUNT   SHARES   AMOUNT    CAPITAL     SHARES   AMOUNT       DEFICIT)
                                     ------   ------   ------   ------   ----------   ------   ------   -----------------
                                                                        (IN THOUSANDS)
<S>                                  <C>      <C>      <C>      <C>      <C>          <C>      <C>      <C>
Balance at December 31, 1999.......     --    $  --    15,631    $156    $  198,295     --     $  --        $(58,440)
  Stock issuance for EPGC merger...     --       --    15,236     152       165,204     --        --              --
  Merger costs paid by principal
    stockholder....................     --       --        --      --         2,895     --        --              --
  Common stock issuance from
    initial public offering........     --       --     7,535      75       103,836     --        --              --
  Option plan compensation.........     --       --        --      --         2,156     --        --              --
  Stock options exercised..........     --       --        13       1           140     --        --              --
  Stock issuance to directors......     --       --         4      --            50     --        --              --
  Net income.......................     --       --        --      --            --     --        --          43,536
                                     -----    -----    ------    ----    ----------    ---     -----        --------
Balance at December 31, 2000.......     --       --    38,419     384       472,576     --        --         (14,904)
  Stock issuance for Belco
    merger.........................  2,930       29    13,587     136       403,959     --        --              --
  Repurchase of common stock.......     --       --        --      --            --    (30)     (408)             --
  Option plan compensation.........     --       --        --      --           367     --        --              --
  Stock options exercised..........     --       --        51       1           706     --        --              --
  Preferred stock dividends paid...     --       --        --      --            --     --        --          (1,587)
  Restricted stock issued..........     --       --        36      --           352     --        --              --
Comprehensive income:
    Net income.....................     --       --        --      --            --     --        --          49,821
    Cumulative effect of change in
      accounting principle.........
    Change in fair value of
      derivative hedging
      instruments..................
    Hedge settlements reclassified
      to income....................
      Total other comprehensive
        income.....................
                                     -----    -----    ------    ----    ----------    ---     -----        --------
Balance at December 31, 2001.......  2,930       29    52,093     521       877,960    (30)     (408)         33,330
  Proceeds from issuance of common
    stock..........................     --       --    14,625     146       266,290     --        --              --
  Repurchase of common stock.......     --       --        --      --            --     (4)      (61)             --
  Option plan compensation.........     --       --        --      --         4,333     --        --              --
  Stock options exercised..........     --       --       105       1         1,467     --        --              --
  Stock issuance to directors......     --       --        --      --            20     --        --              --
  Preferred stock dividends paid...     --       --        --      --            --     --        --          (4,762)
  Restricted stock issued..........     --       --        --      --           275     --        --              --
Comprehensive income:
    Net loss.......................     --       --        --      --            --     --        --         (28,566)
    Change in fair value of
      derivative hedging
      instruments..................
    Hedge settlements reclassified
      to income....................
    Currency translation
      adjustment...................
      Total other comprehensive
        income.....................
                                     -----    -----    ------    ----    ----------    ---     -----        --------
Balance at December 31, 2002.......  2,930    $  29    66,823    $668    $1,150,345    (34)    $(469)       $      2
                                     =====    =====    ======    ====    ==========    ===     =====        ========

<Caption>
                                      ACCUMULATED
                                         OTHER
                                     COMPREHENSIVE   STOCKHOLDERS'
                                     INCOME (LOSS)   EQUITY TOTAL
                                     -------------   -------------
                                            (IN THOUSANDS)
<S>                                  <C>             <C>
Balance at December 31, 1999.......    $     --       $  140,011
  Stock issuance for EPGC merger...          --          165,356
  Merger costs paid by principal
    stockholder....................          --            2,895
  Common stock issuance from
    initial public offering........          --          103,911
  Option plan compensation.........          --            2,156
  Stock options exercised..........          --              141
  Stock issuance to directors......          --               50
  Net income.......................          --           43,536
                                       --------       ----------
Balance at December 31, 2000.......          --          458,056
  Stock issuance for Belco
    merger.........................          --          404,124
  Repurchase of common stock.......          --             (408)
  Option plan compensation.........          --              367
  Stock options exercised..........          --              707
  Preferred stock dividends paid...          --           (1,587)
  Restricted stock issued..........          --              352
Comprehensive income:
    Net income.....................          --           49,821
    Cumulative effect of change in
      accounting principle.........      (3,100)          (3,100)
    Change in fair value of
      derivative hedging
      instruments..................      13,292           13,292
    Hedge settlements reclassified
      to income....................      (1,328)          (1,328)
                                                      ----------
      Total other comprehensive
        income.....................                       58,685
                                       --------       ----------
Balance at December 31, 2001.......       8,864          920,296
  Proceeds from issuance of common
    stock..........................          --          266,436
  Repurchase of common stock.......          --              (61)
  Option plan compensation.........          --            4,333
  Stock options exercised..........          --            1,468
  Stock issuance to directors......          --               20
  Preferred stock dividends paid...          --           (4,762)
  Restricted stock issued..........          --              275
Comprehensive income:
    Net loss.......................          --          (28,566)
    Change in fair value of
      derivative hedging
      instruments..................     (27,981)         (27,981)
    Hedge settlements reclassified
      to income....................         709              709
    Currency translation
      adjustment...................        (161)            (161)
                                                      ----------
      Total other comprehensive
        income.....................                      (55,999)
                                       --------       ----------
Balance at December 31, 2002.......    $(18,569)      $1,132,006
                                       ========       ==========
</Table>

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

                                       F-6
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                               FOR THE YEAR ENDED DECEMBER 31,
                                                              ---------------------------------
                                                                2002        2001        2000
                                                              ---------   ---------   ---------
                                                                       (IN THOUSANDS)
<S>                                                           <C>         <C>         <C>
Cash flows from operating activities:
  Net income (loss).........................................  $ (28,566)  $  49,821   $  43,536
  Adjustments to reconcile net income (loss) to net cash
    provided by operating activities:
    Depletion, depreciation and amortization................    203,093     124,059      64,856
    Exploratory dry hole costs..............................     19,546      19,273       6,020
    Impairment of proved properties.........................     19,700       9,423       2,911
    Impairment of unproved properties.......................      9,961       6,974       5,124
    Deferred income taxes...................................    (17,458)     26,631      23,049
    Stock compensation expense..............................      4,608         719       2,156
    Change in derivative fair value.........................     27,475     (19,283)         --
    Amortization of financing fees..........................      2,438         435          --
    Loss (gain) on sale of assets...........................      1,685         132      (3,130)
    Other...................................................       (274)         --          50
    Changes in assets and liabilities, net of effects of
       acquisitions:
       Decrease (increase) in accounts receivable...........     (2,909)     10,126     (28,678)
       Decrease in net derivative liabilities...............    (10,388)    (18,285)         --
       Decrease (increase) in prepaid expenses and other
         assets.............................................     (5,031)      1,051      (1,139)
       Increase (decrease) in accounts payable..............     (6,573)     (6,240)     17,930
       Increase (decrease) in accrued expenses..............      8,105      (8,474)      9,622
       Increase (decrease) in ad valorem taxes payable......       (851)     (1,130)      2,183
       Increase (decrease) in income taxes payable..........       (477)        301         375
       Decrease in other liabilities........................       (887)       (260)     (1,436)
                                                              ---------   ---------   ---------
Net cash provided by operating activities...................    223,197     195,273     143,429
                                                              ---------   ---------   ---------
Cash flows from investing activities:
  Additions to property and equipment.......................   (147,612)   (187,925)   (102,229)
  Proceeds from sales of assets.............................     13,311       5,536       6,259
  Merger with EPGC..........................................         --          --     (42,403)
  Other acquisitions........................................   (679,890)     (6,319)     (1,454)
  Other.....................................................         28          22        (342)
                                                              ---------   ---------   ---------
Net cash used in investing activities.......................   (814,163)   (188,686)   (140,169)
                                                              ---------   ---------   ---------
Cash flows from financing activities:
  Proceeds from issuance of common stock, net...............    267,787         576     104,052
  Repurchase of common stock................................        (61)       (408)         --
  Proceeds from issuance of long-term debt..................    639,000     590,000      50,000
  Repayments of long-term debt..............................   (285,000)   (577,585)   (156,633)
  Preferred stock dividends.................................     (4,762)     (1,587)         --
  Gain on interest rate swap cancellation...................      3,705          --          --
  Financing fees............................................    (14,273)    (10,153)         --
                                                              ---------   ---------   ---------
Net cash provided by (used in) financing activities.........    606,396         843      (2,581)
                                                              ---------   ---------   ---------
Net increase in cash and cash equivalents...................     15,430       7,430         679
Effect of exchange rate changes on cash and cash
  equivalents...............................................       (253)         --          --
Cash and cash equivalents, beginning of year................     27,584      20,154      19,475
                                                              ---------   ---------   ---------
Cash and cash equivalents, end of year......................  $  42,761   $  27,584   $  20,154
                                                              =========   =========   =========
Supplemental cash flow information:
  Cash paid for interest....................................  $  37,426   $  14,065   $  10,649
                                                              =========   =========   =========
  Cash paid for income taxes................................  $      44   $   1,700   $     300
                                                              =========   =========   =========
Supplemental schedule of non-cash investing and financing
  activities:
  Common stock and stock options issued in connection with
    the Belco and EPGC mergers, respectively................  $      --   $ 349,919   $ 165,356
                                                              =========   =========   =========
  Liabilities and preferred stock assumed in connection with
    the
    Belco and EPGC mergers, respectively....................  $      --   $ 662,089   $   1,850
                                                              =========   =========   =========
    EPGC merger expenses paid by parent.....................  $      --   $      --   $   2,895
                                                              =========   =========   =========
</Table>

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

                                       F-7
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     On August 21, 2001, the stockholders of each of Westport Resources
Corporation, a Delaware corporation ("Old Westport"), and Belco Oil & Gas Corp.,
a Nevada corporation ("Belco"), approved the Agreement and Plan of Merger dated
as of June 8, 2001 (the "Merger Agreement") between Belco and Old Westport.
Pursuant to the Merger Agreement, Old Westport was merged with and into Belco
(the "Merger"), with Belco surviving as the legal entity and changing its name
to Westport Resources Corporation (the "Company" or "Westport"). The merger of
Old Westport into Belco was accounted for as a purchase transaction for
financial accounting purposes. Because former Old Westport stockholders owned a
majority of the outstanding Westport common stock as a result of the Merger, the
Merger was accounted for as a reverse acquisition in which Old Westport is the
purchaser of Belco. Business activities of the Company include the exploration
for and production of oil and natural gas primarily in the Gulf of Mexico, the
Rocky Mountains, the Gulf Coast and the West Texas/Mid Continent area.

     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 cash
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.

  TRANSPORTATION COSTS

     In accordance with Emerging Issues Task Force Issue No. 00-10, "Accounting
for Shipping and Handling Fees and Costs," the Company excludes the effects of
direct transportation costs from oil and gas revenues and records such
transportation costs as a separate line in the statement of operations.

  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, 2002 and 2001 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. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." SFAS No. 144 supersedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
SFAS No. 144 establishes a single accounting model for long-lived assets to be
disposed of by sale and requires that those long-lived assets be measured at the
lower of carrying amount or fair value

                                       F-8
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)


less cost to sell, whether reported in continuing operations or in discontinued
operations. In applying this statement, the Company estimates the expected
future cash flows of its oil and gas properties, on a field-by-field basis, and
compares such future cash flows to the carrying amount of the oil and gas
properties to determine if the carrying amount is recoverable. If the carrying
amount exceeds the estimated undiscounted future cash flows, the Company will
adjust the carrying amount of the oil and gas properties to fair value. The
factors used to determine fair value include estimates of proved reserves,
future commodity prices, future production estimates, anticipated capital
expenditures, and a discount rate commensurate with the risk associated with
realizing the expected future cash flows. The Company has chosen to use the
traditional present value approach to determine the fair value as opposed to the
expected present value method. In the traditional present value approach, a
single set of estimated cash flows and a single interest rate (commensurate with
the risk) are used to estimate fair value. In the expected present value
approach, multiple cash flow scenarios reflecting the range of possible outcomes
and a risk-free rate are used to estimate fair value. Using the expected present
value method could result in different (and possibly higher) amounts for
property impairments than those calculated using the traditional present value
method. In 2002, 2001 and 2000, the Company recorded proved property impairments
of $19.7 million, $9.4 million and $2.9 million, respectively. The impairments
for 2002 consisted of $12.2 million for Wyoming, North Dakota and Montana oil
and natural gas properties in the Northern Division, $1.4 million for offshore
oil and natural gas properties in the Gulf of Mexico Division and $6.1 million
for Texas and Oklahoma oil and natural gas properties in the Southern Division.
The impairments for 2001 consisted of $5.8 million for Wyoming oil and natural
gas properties in the Northern Division, $3.1 million for offshore oil and
natural gas properties in the Gulf of Mexico Division and $0.5 million for
Oklahoma oil and natural gas properties in the Southern Division. The
impairments for 2000 consisted of $1.7 million for Wyoming oil and natural gas
properties in the Northern Division, $0.9 million for an offshore oil and
natural gas property in the Gulf of Mexico Division and $0.3 million for a
Louisiana oil and natural gas property in the Southern Division. Several factors
can cause a producing oil and natural gas property to become impaired, including
a decrease in oil and natural gas prices resulting in a decrease in oil and
natural gas reserve value, unsuccessful development drilling and a decline in
oil and natural gas reserve value due to reserve volume reductions in
underperforming fields. Future changes in any of the above-referenced factors
could result in the Company recording proved property impairment charges in
future periods. Gains and losses resulting from the disposition of proved
properties are included in operations.



     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. The amortizable base of the Company's offshore properties includes
estimated dismantlement, restoration and abandonment costs, net of estimated
salvage values. The Company will adopt SFAS 143 "Accounting for Asset Retirement
Obligations" on January 1, 2003 for all properties. SFAS 143 requires that an
asset retirement cost be capitalized as part of the cost of the asset. Unproved
properties are assessed periodically on a project-by-project basis to determine
whether an impairment has occurred. Management's assessment of the results of
exploration activities, commodity price outlooks, planned future sales or
expiration of all or a portion of such projects impact the amount and timing of
impairment provisions. In 2002, 2001 and 2000, the Company recorded unproved
property impairments of $10.0 million, $7.0 million and $5.1 million,
respectively. The impairments for 2002 consisted of $3.9 million for Wyoming and
North Dakota leases in the Northern Division, $4.0 million for offshore leases
in the Gulf of Mexico Division and $2.1 million for Texas and Louisiana leases
in the Southern Division. The impairments for 2001 consisted of $7.0 million for
offshore leases held in the Gulf of Mexico Division. The impairments for 2000
consisted of $2.9 million for North Dakota and Wyoming leases in the Northern
Division, $1.5 million for offshore leases in the Gulf of Mexico Division and
$0.7 million for Kansas and Louisiana leases in the Southern Division. Factors
leading to recording unproved property impairments include lease expirations and
an assessment of the lack of exploration opportunities existing on a lease.
Future changes in any of the above-referenced factors could result in the
Company recording unproved property impairment charges in future periods. Sales


                                       F-9
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

  CAPITALIZED INTEREST

     The Company capitalizes interest on expenditures of significant exploration
and development projects while activities are in progress to bring the assets to
their intended use. The Company began capitalizing interest in 2002 in which
$45,000 was capitalized.

  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 to purchase common shares were excluded from the
computation of diluted earnings per share in 2002 because they were antidilutive
as a result of the Company's net loss in that year. Dilutive securities of the
Company consist entirely of outstanding options to purchase the Company's common
stock. The Company's 6 1/2% convertible preferred stock was antidilutive for the
period it has been outstanding.

  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 basis 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.

  BUILDING, OFFICE FURNITURE AND EQUIPMENT AND LEASEHOLD IMPROVEMENTS

     Building, office furniture and equipment are stated at cost and are
depreciated using the straight-line method over their estimated useful lives of
three to 20 years. Leasehold improvements are amortized over the life of the
related lease. Maintenance and repairs are charged to expense as incurred. Gains
or losses on dispositions of office furniture and equipment are included in
operations.

  DERIVATIVE 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 future contracts, swaps or
options which are generally placed with major financial institutions or with

                                       F-10
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

     On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." Under SFAS No. 133 all
derivative instruments are recorded on the balance sheet at fair value. Changes
in the derivative's fair value are recognized currently in earnings unless
specific hedge accounting criteria are met. For qualifying cash flow hedges, the
gain or loss on the derivative is deferred in accumulated other comprehensive
income (loss) to the extent the hedge is effective. For qualifying fair value
hedges, the gain or loss on the derivative is offset by related results of the
hedged item in the income statement. Gains and losses on hedging instruments
included in accumulated other comprehensive income (loss) are reclassified to
oil and natural gas sales revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for hedge accounting
treatment are recorded as derivative assets and liabilities at fair value in the
consolidated balance sheet, and the associated unrealized gains and losses are
recorded as current expense or income in the consolidated statement of
operations. While such derivative contracts do not qualify for hedge accounting,
management believes these contracts can be utilized as an effective component of
CPRM activities to help reduce volatility of expected revenues. See Notes 3 and
7.

  STOCK COMPENSATION EXPENSE

     Stock compensation expense consists of noncash charges resulting from the
application of the provisions of FASB Interpretation No. 44 to certain stock
options granted to employees and issuance of restricted stock to certain
employees. Under Interpretation No. 44 the Company is required to measure
compensation cost on stock options that are considered to be variable awards
until the date of exercise, forfeiture or expiration of such options.
Compensation cost is measured for the amount of any increases in the Company
stock price and recognized over the remaining vesting period of the options. Any
decrease in the Company stock price will be recognized as a decrease in
compensation cost limited to the amount of compensation cost previously
recognized as a result of an increase in the Company stock price.

  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 and the interest rate swaps in place that hedge the fair
value of a portion of the senior subordinated notes.

  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

                                       F-11
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

  COMPREHENSIVE INCOME

     The Company follows the provisions of SFAS No. 130, "Reporting
Comprehensive Income," which 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 owners.

  RECENT ACCOUNTING PRONOUNCEMENTS


     In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 142, "Goodwill and Other Intangible Assets," which addresses, among other
things, the financial accounting and reporting for goodwill subsequent to an
acquisition. The new standard eliminates the requirement to amortize acquired
goodwill; instead, such goodwill is to be reviewed at least annually for
impairment. Westport recorded goodwill in connection with the Merger for its
cost or investment in excess of the fair value of the net acquired assets as of
August 21, 2001. In accordance with the provisions of SFAS No. 142 no goodwill
amortization has been recorded. Westport adopted SFAS No. 142 effective January
1, 2002.



     In accordance with SFAS No. 142, Westport was required to perform an
initial impairment review of its goodwill as of January 1, 2002 and will perform
an annual impairment review hereafter. Westport completed the initial step of
the transitional goodwill impairment test during the second quarter of fiscal
2002 in accordance with the provisions of SFAS No. 142, which requires that this
step be completed within six months from the date of adoption. This step of the
goodwill impairment test compares the fair value of a reporting unit with its
carrying amount, including goodwill. Based on results of these comparisons,
goodwill in each of Westport's reporting units had not been impaired as of June
30, 2002. The factors used to determine fair value include estimates of proved
reserves, future commodity prices, future production estimates, anticipated
capital expenditures, and a discount rate commensurate with the risk associated
with realizing the expected future cash flows. The Company has chosen to use the
traditional present value approach to determine the fair value as opposed to the
expected present value method. In the traditional present value approach, a
single set of estimated cash flows and a single interest rate (commensurate with
the risk) are used to estimate fair value. In the expected present value
approach, multiple cash flow scenarios reflecting the range of possible outcomes
and a risk-free rate are used to estimate fair value. Using the expected present
value method could result in different (and possibly higher) impairment charges
than those calculated using the traditional present value method. Westport
performed its annual impairment review as of December 31, 2002 and based on this
goodwill in each of its reporting units had not been impaired.



     At the closing of the Merger the Company prepared a preliminary allocation
of the purchase price among the assets and liabilities as of the closing date
based on the information provided by Belco. The purchase price exceeded the fair
value of the assets acquired and, as a result, the Company recorded goodwill.



     In its pre-closing engineering review of Belco's properties, the Company
focused on the proved reserves, which accounted for the majority of the value of
the transaction. For those reserves, the Company reviewed the data provided by
Belco and engaged independent reserve engineers to confirm the Company's reserve
estimates. For Belco's lower-valued properties the Company focused on the proved
reserves that were generating current cash flow (i.e., the proved developed
producing assets). Because of the large volume of data involved, limited
available review time and relatively low portion of the total transaction value
represented, the Company generally relied on reserve engineering presented by
Belco with respect to the proved non-producing and proved undeveloped reserves
on these lower-valued properties. The Company used this information in making
its preliminary allocation of the purchase price


                                       F-12
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)


and subsequently conducted a thorough post-closing review of these properties as
part of its final purchase price allocation.



     The post-closing evaluation was completed in the second quarter of 2002,
resulting in the reclassification to goodwill of $19.7 million from unproved
properties and $10.3 million from proved properties. The Company also increased
goodwill by $1.9 million to reflect additional Merger costs and other
miscellaneous adjustments. The information that caused the adjustments was not
known by the Company at closing because the volume of data relating to the
acquired enterprise and limited time available between execution of the Merger
agreement and the closing made a detailed review impracticable.



     The $19.7 million adjustment to unproved properties resulted from a
determination that the actual inventory of net unproved acreage acquired in the
Merger consisted of 517,248 net undeveloped acres, rather than the 707,179 net
undeveloped acres reported by Belco in connection with the Merger. This 189,931
net acre reduction was the result of three components affecting Belco's net
undeveloped acreage figures: (1) expiration of rights to certain acreage prior
to the closing date; (2) the failure to initiate or cessation of development
activities necessary to maintain unearned option acreage; and (3) a duplication
of acreage that Westport had included in proved property. Using the same per
acre market value used in its original valuation, Westport reduced the value
assigned to the reduced acreage included in Belco's unproved properties by $19.7
million and transferred that amount to goodwill.



     After the Merger, the Company engaged a third party engineering firm to
assess the fair value of certain lower-valued Belco properties for possible sale
or trade. These properties included approximately 30 fields comprising a portion
of the lower 15% of the value of Belco properties acquired in the Merger. The
third party engineering firm determined that the fair value of some those
properties was lower than had been estimated at the time of the Merger. The
reduction in fair value was based on the discovery that anticipated
modifications to waterfloods that had been assumed in the Belco engineering
report used in the Company's preliminary valuation had not in fact occurred by
the time of the closing, and were not occurring on the offset or adjacent
leases. As a result, the Company reallocated approximately $10.3 million from
the affected proved properties to goodwill.



     The following table summarizes the goodwill allocation to the reporting
units as of June 30, 2002. There have been no changes to the goodwill allocation
since June 30, 2002.



<Table>
<Caption>
                                                        NORTHERN   SOUTHERN
                                                        DIVISION   DIVISION
                                                        SEGMENT    SEGMENT     TOTAL
                                                        --------   --------   --------
<S>                                                     <C>        <C>        <C>
Goodwill Acquired (August 21, 2001)...................  $33,296    $181,548   $214,844
Adjustments confirmed by information received
  subsequent to the Merger that existed at the date of
  the Merger..........................................       --      31,868     31,868
                                                        -------    --------   --------
Balance as of December 31, 2002.......................  $33,296    $213,416   $246,712
                                                        =======    ========   ========
</Table>


     In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires entities to record the fair value
of liabilities for retirement obligations of acquired assets. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. The Company adopted
SFAS No. 143 on January 1, 2003. Based on current estimates, the Company expects
to record asset retirement obligations of approximately $59 million (using a
7.6% discount rate) and a cumulative effect of change in accounting principle on
prior years in the range of $2 million to $5 million net of tax effects related
to the depreciation and accretion expense that would have been reported had the
fair value of the asset retirement obligation, and corresponding increase in the
carrying amount of the related long-lived asset, been recorded when incurred.

                                       F-13
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS No. 144 establishes a single accounting model
for long-lived assets to be disposed of by sale and requires that those
long-lived assets be measured at the lower of carrying amount or fair value less
cost to sell, whether reported in continuing operations or in discontinued
operations. SFAS No. 144 is effective for fiscal years beginning after December
15, 2001. The Company adopted SFAS No. 144 on January 1, 2002. In 2002 the
Company impaired $12.2 million in the Northern Division, $6.1 in the Southern
Division and $1.4 million in the Gulf of Mexico Division for a total impairment
of $19.7 million of its long-lived assets.

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections."
Prior to the adoption of the provisions of SFAS No. 145, generally accepted
accounting principles ("GAAP") required gains or losses on the early
extinguishment of debt be classified in a company's periodic consolidated
statements of operations as extraordinary gains or losses, net of associated
income taxes, below the determination of income or loss from continuing
operations. SFAS No. 145 changes GAAP to require, except in the case of events
or transactions of a highly unusual and infrequent nature, gains or losses from
the early extinguishment of debt be classified as components of a company's
income or loss from continuing operations. The Company will adopt the provisions
of SFAS No. 145 on January 1, 2003. The adoption of the provisions of SFAS No.
145 is not expected to affect the Company's financial position or results of
operations.

     In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires that a
liability for a cost associated with an exit or disposal activity be recognized
and measured initially at fair value only when the liability is incurred. SFAS
No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002. The adoption of SFAS No. 146 is not expected to have an
effect on the Company's financial position or results of operations.

     In December, 2002 the FASB issued SFAS No. 148, "Accounting for Stock-based
Compensation-Transition and Disclosure." SFAS 148 amend FASB Statement No. 123,
"Accounting for Stock-Based Compensation" to provide alternative methods of
transition for a voluntary change to the fair-value based method of accounting
for stock-based employee compensation. In addition, this Statement amends the
disclosure requirements of Statement 123 to require prominent disclosures in
both annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on the
reported results. The provisions of SFAS 148 has no material impact on us, as we
do not plan to adopt the fair-value method of accounting for stock options at
the current time. We have included the required disclosures in Note 9 to the
Consolidated Financial Statements.

     In November, 2002 the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others -- an interpretation of FASB
Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" (FIN
45). FIN 45 elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under certain
guarantees that it has issued. It also clarifies that a guarantor is required to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligation undertaken in issuing the guarantee. The initial recognition and
initial measurement provisions of FIN 45 are applicable on a prospective basis
to guarantees issued or modified after December 31, 2002, irrespective of the
guarantor's fiscal year-end. The disclosure requirements are effective for
financial statements of interim or annual periods ending after December 15,
2002. The adoption of FIN 45 is not expected to have an effect on the Company's
financial position or results of operations.

                                       F-14
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities -- an interpretation of ARB No. 51"
(FIN 46). FIN 46 is an interpretation of Accounting Research Bulletin 51,
"Consolidated Financial Statements", and addresses consolidation by business
enterprises of variable interest entities (VIE's). The primary objective of the
Interpretation is to provide guidance on the identification of, and financial
reporting for, entities over which control is achieved through means other than
voting rights; such entities are known as VIE's. FIN 46 requires an enterprise
to consolidate a VIE if that enterprise has a variable interest that will absorb
a majority of the entity's expected losses if they occur, receive a majority of
the entity's expected residual returns if they occur, or both. An enterprise
shall consider the rights and obligations conveyed by its variable interests in
making this determination. This guidance applies immediately to variable
interest entities created after January 31, 2003, and to variable interest
entities in which an enterprise obtains an interest after that date. It applies
in the first fiscal year or interim period beginning after June 15, 2003, to
variable interest entities in which an enterprise holds a variable interest that
it acquired before February 1, 2003. At this time, the Company does not have a
VIE.

2.  MERGERS & ACQUISITIONS

  EL PASO ACQUISITION

     On December 17, 2002, effective as of June 1, 2002, the Company acquired
producing properties, undeveloped leaseholds, gathering and compression
facilities and other related assets in the Greater Natural Buttes area of Uintah
County, Utah from affiliates of El Paso Corporation for approximately $507
million, which includes certain purchase price adjustments. The Company's newly
formed Western Division is comprised substantially of these properties.

     The total purchase price of $507 million was allocated as follows (in
thousands):

<Table>
<S>                                                           <C>
Allocation of purchase price:
  Oil and gas properties -- proved..........................  $464,481
  Oil and gas properties -- unproved........................     3,500
  Gathering assets..........................................    39,185
                                                              --------
     Total allocation.......................................  $507,166
                                                              ========
</Table>

  PRO FORMA RESULTS OF OPERATIONS (UNAUDITED)

     The following table reflects the pro forma results of operations for the
respective years ended December 31, 2002 and 2001 as though the Acquisition and
the Merger, discussed below, had occurred as of January 1 of each year
presented. The pro forma amounts are not necessarily indicative of the results
that may be reported in the future. The Company began consolidating the results
of the Acquisition with the results of Westport as of December 17, 2002.


<Table>
<Caption>
                                                                FOR THE YEAR ENDED
                                                                   DECEMBER 31,
                                                              -----------------------
                                                                 2002         2001
                                                              ----------   ----------
                                                                  (IN THOUSANDS,
                                                              EXCEPT PER SHARE DATA)
<S>                                                           <C>          <C>
Revenues....................................................   $460,704     $645,713
Net income (loss)...........................................    (33,746)     124,090
Basic net income (loss) per share...........................      (0.52)        1.82
Diluted net income (loss) per share.........................      (0.52)        1.80
</Table>


                                       F-15
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

  SOUTHEAST TEXAS ACQUISITION

     On September 30, 2002,the Company acquired oil and gas properties located
in southeast Texas, also referred to as the Southeast Texas Acquisition, for a
total cash purchase price of approximately $122.6 million.

     The total purchase price of $122.6 million was allocated as follows (in
thousands):

<Table>
<S>                                                           <C>
Allocation of purchase price:
  Oil and gas properties -- proved..........................  $111,623
  Oil and gas properties -- unproved........................    10,636
  Seismic licenses..........................................     2,936
  Assumed liabilities.......................................    (2,568)
                                                              --------
          Total allocation..................................  $122,627
                                                              ========
</Table>

  BELCO MERGER

     In connection with the Merger on August 21, 2001, the Company consummated a
0.4125 for 1 reverse stock split for existing Belco stockholders (issuing
approximately 13.587 million shares) and issued approximately 38.469 million
shares of common stock to Old Westport stockholders. The Merger was a
non-taxable transaction in which former Old Westport stockholders received a
majority of the Company's common stock. As a result, the Merger was accounted
for using purchase accounting with Old Westport as the accounting survivor. The
Company began consolidating the results of Belco with the results of Old
Westport as of the August 21, 2001 closing date of the Merger.

     The total purchase price of $1,019 million was allocated as follows (in
thousands):

<Table>
<S>                                                           <C>
Purchase Price:
  Fair value of common stock issued.........................  $  341,455
  Fair value of Belco stock options.........................       8,464
  Fair value of liabilities assumed:
     Liabilities from commodity price risk management.......      52,388
     Current liabilities....................................      45,135
     Long-term debt.........................................     422,327
     Deferred taxes.........................................      87,776
     Other liabilities......................................         258
  Fair value of Belco preferred stock.......................      54,205
  Estimated merger costs....................................       7,000
                                                              ----------
          Total purchase price..............................  $1,019,008
                                                              ==========
Allocation of purchase price:
  Oil and gas properties -- proved..........................  $  690,788
  Oil and gas properties -- unproved........................      48,541
  Goodwill..................................................     246,712
  Current assets............................................      27,060
  Other assets..............................................       5,907
                                                              ----------
          Total allocation..................................  $1,019,008
                                                              ==========
</Table>

                                       F-16
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The common stock issued to Belco stockholders in connection with the Merger
was valued at $25.13 per share. The fair value of the Belco stock options
assumed was determined using the Black-Scholes option pricing model. The fair
value of Belco's publicly-traded debt and preferred stock was based on quoted
market prices on August 21, 2001. The deferred taxes recorded were based on the
difference between the historical tax basis of the Belco assets and liabilities
and the acquisition costs.

3.  COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

     The Company periodically enters into commodity price risk management
("CPRM") transactions to manage its exposure to oil and gas price volatility.
CPRM transactions may take the form of futures contracts, swaps or options. All
CPRM data is presented in accordance with requirements of SFAS No. 133 which the
Company adopted on January 1, 2001. Accordingly, unrealized gains and losses
related to the change in fair market value of derivative contracts which qualify
and are designated as cash flow hedges are recorded as other comprehensive
income or loss and such amounts are reclassified to oil and gas sales revenues
as the associated production occurs. Derivative contracts that do not qualify
for hedge accounting treatment are recorded as derivative assets and liabilities
at market value in the consolidated balance sheet, and the associated unrealized
gains and losses are recorded as current expense or income in the consolidated
statement of operations. While such derivative contracts do not qualify for
hedge accounting, management believes these contracts can be utilized as an
effective component of CPRM activities.

     Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a
derivative liability of approximately $4.7 million for the fair market value of
its derivative instruments designated as cash flow hedges and a corresponding
loss of approximately $3.1 million (net of tax effect of $1.6 million) as a
cumulative effect of a change in accounting principle in other comprehensive
income. For the years ended December 31, 2002 and 2001, the Company reclassified
approximately $1.3 million of hedging losses and $2.1 million of hedging gains
out of accumulated other comprehensive income into oil and gas sales revenues,
respectively. The hedging losses and gains reclassified to revenues include cash
losses of $8.2 million and $4.5 million for the years ended December 31, 2002
and 2001, respectively. For the year ended December 31, 2000, the Company
recorded a loss in hedging settlements of $24.6 million. As of December 31,
2002, the Company expects to reclassify approximately $15 million of loss into
earnings from accumulated other comprehensive income during 2003.

     For the years ended December 31, 2002 and 2001, the Company recorded
non-hedge CPRM settlements of $0.8 million and $15.3 million and unrealized
non-hedge change in fair value of derivatives of ($26.7) which included a $0.1
million ineffectiveness loss and $14.3 million with no ineffectiveness,
respectively. The majority, $18.2 million, of the non-hedge loss in fair value
of derivatives for 2002 was related to derivative contracts entered into in
anticipation of the expected production acquired in the El Paso acquisition.
Upon closing of the transaction the derivative contracts qualified for hedge
accounting treatment. The non-hedge CPRM settlements reflect cash settlements of
($2.9) million and $3.6 million for the years ended December 31, 2002 and 2001
respectively. For the year ended December 31, 2000, the Company recorded an
unrealized non-hedge loss in fair value of derivatives of $0.7 million.

     As of December 31, 2002, the Company had approximately 5.2 million barrels
of oil and 70.7 Bcf of natural gas subject to CPRM contracts for 2003. Of these
contracts, all of the oil and 63.4 Bcf of the natural gas contracts are subject
to weighted average NYMEX floor prices of $23.18 per barrel and $3.78 per Mmbtu
and weighted average NYMEX ceiling prices of $25.16 per barrel and $4.20 per
Mmbtu, respectively, excluding the effect, if any, of the three-way floor price.
The remaining 2003 gas CPRM contract settlements are calculated based on the
Northwest Pipeline Rocky Mountain Index ("NWPRM") with weighted average NWPRM
floor and ceiling prices of $3.00 and $3.29, respectively. In addition, included
in the 63.4 Bcf of natural gas contracts, the Company has entered into basis
swaps

                                       F-17
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

covering 13.4 Bcf of natural gas for 2003 that lock in the pricing differential
between NYMEX and NWPRM at a weighted average price differential of $0.67 per
Mmbtu and 3.7 Bcf for 2003 that lock in the pricing differential between NYMEX
and Colorado Interstate Gas Index ("CIG") at a weighted average price
differential of $0.95 per Mmbtu. The Company has approximately .4 million
barrels of oil and 45.7 Bcf of natural gas subject to CPRM contracts for 2004.
Of these contracts, all of the oil and 38.3 Bcf of the natural gas contracts are
subject to weighted average NYMEX floor prices of $23.60 per barrel and $3.83
per Mmbtu and weighted average NYMEX ceiling prices of $23.60 per barrel and
$4.06 per Mmbtu, respectively, excluding the effect, if any, of the three-way
floor price. The remaining 2004 gas CPRM contract settlements are calculated
based on the NWPRM Index with weighted average swap price of $3.20 per Mmbtu. In
addition, included in the 38.3 Bcf of natural gas contracts, the Company has
entered into basis swaps covering 3.7 Bcf of natural gas for 2004 that lock in
the pricing differential between NYMEX and NWPRM at a weighted average price
differential of $0.66 per Mmbtu and 1.8 Bcf of natural gas for 2004 that lock in
the pricing differential between NYMEX and CIG at a weighted average
differential of $0.81. The Company has approximately 1.8 Bcf of natural gas
subject to CPRM contracts for 2005 with a weighted average NYMEX swap price of
$3.85 per Mmbtu. The contracts discussed above represent the Company's hedge and
non-hedge positions.

     The tables below provide details about the volumes and prices of all open
CPRM, hedge and non-hedge commitments, as of December 31, 2002.

<Table>
<Caption>
                                                               2003      2004      2005
                                                              -------   -------   ------
<S>                                                           <C>       <C>       <C>
HEDGES
  GAS
     NYMEX Price Swaps Sold -- receive fixed price (thousand
       Mmbtu)(1)............................................   31,950    18,300    1,825
       Weighted average price per Mmbtu.....................  $  4.01   $  3.92   $ 3.85
     NWPRM Price Swaps Sold -- receive fixed price (thousand
       Mmbtu)(2)............................................       --     7,320       --
       Weighted average price per Mmbtu.....................       --   $  3.20       --
     NYMEX Collars Sold (thousand Mmbtu)(3).................   22,383    16,380       --
       Weighted average floor price per Mmbtu...............  $  3.61   $  3.70       --
       Weighted average ceiling price per Mmbtu.............  $  4.29   $  4.00       --
     NWPRM Collars Sold (thousand Mmbtu)(4).................    7,300        --       --
       Weighted average floor price per Mmbtu...............  $  3.00        --       --
       Weighted averaged ceiling price per Mmbtu............  $  3.29        --       --
     NYMEX Three -- way Collars (thousand Mmbtu)(3)(5)......    8,030     3,660       --
       Weighted average floor price per Mmbtu...............  $  3.39   $  4.00       --
       Weighted average ceiling price per Mmbtu.............  $  4.73   $  5.00       --
       Three -- way average floor price per Mmbtu...........  $  2.22   $  3.15       --
     Basic Swaps(6)
       NWPRM (thousand Mmbtu)...............................   13,430     3,660       --
          Average differential price per Mmbtu..............  $  0.67   $  0.66       --
       CIG (thousand Mmbtu).................................    3,650     1,830       --
          Average differential price per Mmbtu..............  $  0.95   $  0.81       --
</Table>

                                       F-18
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

<Table>
<Caption>
                                                               2003      2004      2005
                                                              -------   -------   ------
<S>                                                           <C>       <C>       <C>
  OIL
     NYMEX Price Swaps Sold -- receive fixed price
       (Mbbls)(1)...........................................      875       366       --
       Weighted average price per bbl.......................  $ 21.80   $ 23.60       --
     NYMEX Collars Sold (Mbbls)(3)..........................    1,980        --       --
       Weighted average floor price per bbl.................  $ 24.45        --       --
       Weighted average ceiling price per bbl...............  $ 26.45        --       --
     NYMEX Three-way Collars (Mbbls)(3)(5)..................    1,995        --       --
       Weighted average floor price per bbl.................  $ 23.18        --       --
       Weighted average ceiling price per bbl...............  $ 26.30        --       --
       Three-way average floor price per bbl................  $ 18.90        --       --
NON HEDGES
  OIL
     NYMEX Price Swaps Sold -- receive fixed price
       (Mbbls)(1)...........................................      300        --       --
       Weighted average price per bbl.......................  $ 18.86        --       --
</Table>

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

(1) For any particular NYMEX swap sold transaction, the Counterparty is required
    to make a payment to Westport in the event that the NYMEX Reference Price
    for any settlement period is less than the swap price for such hedge, and
    Westport is required to make a payment to the Counterparty in the event that
    the NYMEX Reference Price for any settlement period is greater than the swap
    price for such hedge.

(2) For any particular NWPRM swap sold transaction, the Counterparty is required
    to make a payment to Westport in the event that the NWPRM Index Price for
    any settlement period is less than the swap price for such hedge, and
    Westport is required to make a payment to the Counterparty in the event that
    the NWPRM Index Price for any settlement period is greater than the swap
    price for such hedge.

(3) For any particular NYMEX collar transaction, the Counterparty is required to
    make a payment to Westport if the average NYMEX Reference Price for the
    reference period is below the floor price for such transaction, and Westport
    is required to make payment to the Counterparty if the average NYMEX
    Reference Price is above the ceiling price of such transaction.

(4) For any particular NWPRM collar transaction, the Counterparty is required to
    make a payment to Westport if the average NWPRM Index Price for the
    reference period is below the floor price for such transaction, and Westport
    is required to make payment to the Counterparty if the average NWPRM Index
    Price is above the ceiling price of such transaction.

(5) NYMEX three-way collars are settled as described in footnote (3) above, with
    the following exceptions: if the NYMEX reference price falls below the
    three-way floor price, the average floor price is adjusted by the amount by
    which the NYMEX reference price is below the three-way floor price. For
    example, on a three-way oil collar, if the NYMEX reference price is $18.00
    per bbl during the term of the 2003 three-way collars, then the effective
    average floor price would be $22.28 per bbl.

(6) For any particular basis swap, the counterparty is required to make a
    payment to Westport in the event that the difference between the NYMEX
    Reference Price and the applicable published index (NWPRM or CIG) for any
    settlement period is greater than the swap differential price for such
    hedge, and Westport is required to make a payment to the counterparty in the
    event that the

                                       F-19
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

    difference between the NYMEX Reference Price and the applicable published
    index (NMPRM or CIG) for any settlement period is less than the swap
    differential price for such hedge.

     Also see Note 7 of the Consolidated Financial Statements for interest rate
hedge disclosures.

4.  EARNINGS PER SHARE AND OTHER COMPREHENSIVE INCOME (LOSS)

  EARNINGS PER SHARE

     Basic earnings per share are computed by dividing net earnings attributable
to common stock by the weighted average number of common shares outstanding
during each period, excluding treasury shares. Diluted earnings per share are
computed by adjusting the average number of common shares outstanding for the
dilutive effect, if any, of convertible preferred stock and stock options.

     The following sets forth the calculation of basic and diluted earnings per
share (in thousands, except per share data):

<Table>
<Caption>
                                                              FOR THE YEAR ENDED
                                                                 DECEMBER 31,
                                                              ------------------
                                                                2002      2001
                                                              --------   -------
<S>                                                           <C>        <C>
Net income (loss) available to common stockholders..........  $(33,328)  $48,234
                                                              ========   =======
Weighted average common shares outstanding..................    53,007    43,408
  Add dilutive effects of employee stock options............        --       760
                                                              --------   -------
Weighted average common shares outstanding including the
  effects of dilutive securities............................    53,007    44,168
                                                              ========   =======
Basic earnings per share....................................  $  (0.63)  $  1.11
                                                              ========   =======
Diluted earnings per share..................................  $  (0.63)  $  1.09
                                                              ========   =======
</Table>

  COMPREHENSIVE INCOME (LOSS)

     The Company follows SFAS No. 130, "Reporting Comprehensive Income," which
establishes standards for reporting comprehensive income. In addition to net
income, comprehensive income includes all changes in equity during a period,
except those resulting from investments and distributions to the

                                       F-20
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

owners of the Company. The components of other comprehensive and related tax
effects for the twelve months ended December 31, 2002 and 2001 are as follows:

<Table>
<Caption>
                                                               FOR THE YEAR ENDED
                                        -----------------------------------------------------------------
                                               DECEMBER 31, 2002                 DECEMBER 31, 2001
                                        --------------------------------   ------------------------------
                                         GROSS     TAX EFFECT     NET       GROSS    TAX EFFECT     NET
                                        --------   ----------   --------   -------   ----------   -------
                                                                  (IN THOUSANDS)
<S>                                     <C>        <C>          <C>        <C>       <C>          <C>
Net income (loss) available to common
  stockholders........................  $(52,880)   $19,552     $(33,328)  $76,871    $(28,637)   $48,234
Other comprehensive income:
  Cumulative effect of change in
     accounting principle.............        --         --           --    (4,882)      1,782     (3,100)
  Change in fair value of derivative
     hedging instruments..............   (44,065)    16,084      (27,981)   20,932      (7,640)    13,292
  Enron non-cash settlements
     reclassified to income...........    (1,443)       527         (916)    1,165        (425)       740
  Hedge settlements reclassified to
     income...........................     2,559       (934)       1,625    (3,257)      1,189     (2,068)
  Currency translation adjustment.....      (254)        93         (161)       --          --         --
                                        --------    -------     --------   -------    --------    -------
Comprehensive income (loss)...........  $(96,083)   $35,322     $(60,761)  $90,829    $(33,731)   $57,098
                                        ========    =======     ========   =======    ========    =======
</Table>

5.  CONCENTRATION OF CREDIT RISK

     The Company has accounts with separate banks in Denver, Colorado, Dallas,
Texas and Calgary, Canada. The Company invests substantially all available cash
in overnight investment accounts consisting of U.S. Treasury obligations and
commercial paper. At December 31, 2002, the balance in the overnight investment
accounts was $35.8 million.

     The Company sells its oil and natural gas production to companies it
believes to be creditworthy. Actual losses relating to product sales have been
immaterial and currently the Company does require collateral from certain
companies.

6.  INCOME TAXES

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

<Table>
<Caption>
                                                         FOR THE YEAR ENDED DECEMBER 31,
                                                         -------------------------------
                                                           2002        2001       2000
                                                         ---------   --------   --------
                                                                 (IN THOUSANDS)
<S>                                                      <C>         <C>        <C>
Current:
  Federal..............................................  $ (1,894)   $ 1,806    $   675
  State................................................      (200)       200         --
                                                         --------    -------    -------
                                                           (2,094)     2,006        675
                                                         --------    -------    -------
Deferred:
  Federal..............................................   (16,736)    25,654     22,289
  State................................................      (722)       977        760
                                                         --------    -------    -------
                                                          (17,458)    26,631     23,049
                                                         --------    -------    -------
Provision for income taxes.............................  $(19,552)   $28,637    $23,724
                                                         ========    =======    =======
</Table>

                                       F-21
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The difference between the provision 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,
                                                         -------------------------------
                                                           2002        2001       2000
                                                         ---------   --------   --------
                                                                 (IN THOUSANDS)
<S>                                                      <C>         <C>        <C>
Federal statutory rate of 35%..........................  $(16,841)   $27,460    $23,541
State income taxes, net of Federal effect..............      (722)     1,177        760
Change in valuation allowance..........................        --         --       (460)
Other permanent differences............................        21         --       (117)
Other..................................................        84         --         --
Adjustment to prior year's estimated tax liability.....    (2,094)        --         --
                                                         --------    -------    -------
                                                         $(19,552)   $28,637    $23,724
                                                         ========    =======    =======
</Table>

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

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              ---------------------
                                                                2002        2001
                                                              ---------   ---------
                                                                 (IN THOUSANDS)
<S>                                                           <C>         <C>
Oil and natural gas properties..............................  $(187,347)  $(222,539)
Taxes related to net hedging liabilities (assets)...........     14,910      (5,095)
Taxes related to foreign currency translation liabilities...         92          --
Net operating loss carryforward.............................     42,773      64,506
Capital loss carryforward...................................      3,642       3,723
Alternative minimum tax credit..............................      1,400       1,400
                                                              ---------   ---------
  Net deferred tax liability................................  $(124,530)  $(158,005)
                                                              =========   =========
</Table>

     As of December 31, 2002, the Company had net operating loss carryforwards
for income tax purposes of approximately $116.9 million, which expire between
2018 and 2022 and may be utilized to reduce future tax liability of the Company.
The utilization of substantially all of these loss carryforwards, acquired in
the Merger, will be limited to approximately $16.3 million per year.

7.  LONG-TERM DEBT

     Long-term debt consisted of:

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              ---------------------
                                                                2002         2001
                                                              --------     --------
                                                                 (IN THOUSANDS)
<S>                                                           <C>          <C>
8 1/4% senior subordinated notes due 2011...................  $591,771(1)  $272,147(2)
8 7/8% senior subordinated notes due 2007...................   127,587(3)   122,077(2)
  Revolving credit facility due on July 1, 2005.............        --       35,000
  Revolving credit facility due on December 16, 2006........    80,000           --
                                                              --------     --------
  Less current portion......................................        --           --
                                                              --------     --------
                                                              $799,358     $429,224
                                                              ========     ========
</Table>

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

(1) The balance noted above at December 31, 2002 of the 8 1/4% Senior
    Subordinated Notes reflects an increase of $8,916,000 related to the premium
    recorded with the issuance of the additional debt

                                       F-22
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

    security issued December 17, 2002 and an increase of $7,855,000 related to
    fair market value adjustments recorded as a result of the Company's interest
    rate swaps accounted for as fair value hedges. See Interest Rate
    Swaps -- Hedges below.

(2) The balances noted above at December 31, 2001 of the 8 1/4% Senior
    Subordinated Notes and the 8 7/8% Senior Subordinated Notes reflect
    reductions of $2,853,000 and $2,353,000 related to fair market value
    adjustments recorded as a result of the Company's interest rate swaps
    accounted for as fair value hedges. See Interest Rate Swaps -- Hedges below.

(3) The balance noted above at December 31, 2002 of the 8 7/8% Senior
    Subordinated reflects an increase of $3,489,000 related to the gain on the
    cancellation of the fair market value hedge, which will be amortized over
    the remaining life of the note.

  REVOLVING CREDIT FACILITY

     The Company entered into a new credit facility (the "Revolving Credit
Facility") on December 17, 2002 with JPMorgan Chase Bank and Credit Suisse First
Boston Corporation, for a maximum committed amount of $600 million and an
initial borrowing base of approximately $470 million. The facility matures on
December 16, 2006 and contains covenants and default provisions customary for
similar credit facilities. We made borrowings under the Credit Facility to
refinance all outstanding indebtedness under our previous revolving credit
facility and to pay general corporate expenses.

     Advances under the Credit Facility are in the form of either an ABR loan or
a Eurodollar loan. The interest on an ABR loan is a fluctuating rate based upon
the highest of: (1) the rate of interest announced by JPMorgan Chase Bank as its
prime rate; (2) the secondary market rate for three-month certificates of
deposits plus 1%; or (3) the Federal funds effective rate plus 0.5%, plus in
each case a margin of 0% to 0.625% based upon the ratio of total debt to EBITDAX
and the ratings of our senior unsecured debt as issued by Standard and Poor's
Rating Group and Moody's Investors Service, Inc. EBITDAX is defined as net
income plus interest expense, income tax expense, and amounts attributable to
depreciation, depletion, exploration, amortization and other non-cash charges
and expenses, but excluding changes in value of certain hedging instruments and
extraordinary or nonrecurring gains or losses, subject to certain other
specified adjustments. The interest on a Eurodollar loan is a fluctuating rate
based upon the rate at which Eurodollar deposits in the London interbank market
are quoted plus a margin of 1.000% to 1.875% based upon the ratio of total debt
to EBITDAX and the ratings of our senior unsecured debt as issued by Standard
and Poor's Rating Group and Moody's Investors Service, Inc.

     The Revolving Credit Facility contains various covenants and restrictive
provisions including two financial covenants that require the Company to
maintain a current ratio of not less than 1.0 to 1.0 and a ratio of EBITDAX to
consolidated interest expense for the preceding four consecutive fiscal quarters
of not less than 3.0 to 1.0. Commitment fees under the Revolving Credit Facility
range from 0.25% to 0.5% on the average daily amount of the available unused
borrowing capacity based on the rating of our senior unsecured debt as issued by
Standard and Poor's Rating Group and Moody's Investor Service, Inc.

     As of December 31, 2002, we had borrowings and letters of credit issued of
approximately $97.1 million outstanding under the Credit Facility, with a
weighted average interest rate of 3.3% and available unused borrowing capacity
of approximately $372.9 million. The Revolving Credit Facility currently limits
the outstanding letters of credit to $200 million.

     Under the terms of the Revolving Credit Facility the Company must meet
certain tests before it is able to declare or pay any dividend on (other than
dividends payable solely in equity interests of the Company other than
disqualified stock), or make any payment of, or set apart assets for a sinking
or other analogous fund for the purchase, redemption, defeasance, retirement or
other acquisition of, any shares of any class of equity interests of the Company
or any restricted subsidiary, whether now or hereafter

                                       F-23
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

outstanding, or make any other distribution in respect thereof, either directly
or indirectly, whether in cash or property or in obligations of the Company or
any restricted subsidiary.

  8 7/8% SENIOR SUBORDINATED NOTES DUE 2007

     In connection with the Merger, the Company assumed $147 million face
amount, $149 million fair value, of Belco's 8 7/8% Senior Subordinated Notes due
2007. On November 1, 2001, approximately $24.3 million face amount of these
notes was tendered to the Company pursuant to the change of control provisions
of the related indenture. The tender price was equal to 101% of the principal
amount of each note plus accrued and unpaid interest as of October 29, 2001.
Including the premium and accrued interest, the total amount paid was $24.8
million. The Company used borrowings under its previous revolving credit
facility to fund the repayment. No gain or loss was recorded in connection with
the redemption as the fair value of the 8 7/8% Senior Subordinated Notes
recorded in connection with the Merger equaled the redemption cost.

  8 1/4% SENIOR SUBORDINATED NOTES DUE 2011

     On December 17, 2002, the Company issued $300 million in additional
principal amount of 8 1/4% Senior Subordinated Notes Due 2011, or the old notes,
pursuant to Rule 144A under the Securities Act at a price of 103% of the
principal amount, with accrued interest from November 1, 2002. The old notes are
additional debt securities under the Indenture pursuant to which, on November 5,
2001, the Company had issued $275 million of 8 1/4% Senior Subordinated Notes
Due 2011. On March 14, 2002, all of the 2001 notes were exchanged in an exchange
offer for an equal principal amount of the initial exchange notes. The Company
used the proceeds from the sale of the old notes to finance, in part, the
Acquisition. On January 24, 2003, the Company filed the exchange offer
registration statement pursuant to a registration rights agreement relating to
the old notes. In the event the Company fails to comply with some of its
obligations under the registration rights agreement relating to the old notes,
the Company will pay additional interest on the old notes. The exchange offer
registration statement was declared effective by the SEC on January 30, 2003.
The Company was offering to exchange up to $300 million aggregate principal
amount of new 8 1/4% Senior Subordinated Notes Due 2011, or exchange notes, that
have been registered under the Securities Act for an equal principal amount of
old notes. The exchange offer expired at 5 p.m., New York City time, on March 6,
2003. The Company intends to close the exchange offer in March of this year.

     The notes are senior subordinated unsecured obligations of the Company and
are fully and unconditionally guaranteed on a senior subordinated basis by some
of its existing and future restricted subsidiaries. The notes mature on November
1, 2011. The Company pays interest on the notes semiannually on May 1 and
November 1. The first interest payment on the old notes is due on May 1, 2003.
The Company is entitled to redeem the notes in whole or in part on or after
November 1, 2006 for the redemption price set forth in the notes. Prior to
November 1, 2006, the Company is entitled to redeem the notes, in whole but not
in part, at a redemption price equal to the principal amount of the notes plus a
premium. There is no sinking fund for the notes. If the Company fails to comply
with some of its obligations under the registration rights agreement relating to
the old notes, the Company will pay additional interest on the old notes.

  INTEREST RATE SWAPS -- HEDGES

     On November 21, 2001, the Company entered into two separate interest rate
swaps to hedge the fair value of a portion of the 8 7/8% Senior Subordinated
Notes and 8 1/4% Senior Subordinated Notes. The swap on the 8 7/8% Senior
Subordinated Notes had a notional amount of $122.7 million and an expiration
date of September 15, 2007. Under this swap agreement, the Company paid the
counterparty a variable rate

                                       F-24
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(LIBOR +3.44%) and received a fixed rate (8 7/8%). On September 16, 2002 the
interest rate swap on the 8 7/8% Senior Subordinated Notes was terminated
resulting in $5.8 million being paid to the Company. The Company recorded a $2.1
million reduction in interest expense and a $3.7 million fair value gain, which
was added to the outstanding debt balance and will be amortized over the
remaining life of the note. The swap on the 8 1/4% Senior Subordinated Notes has
a notional amount of $100.0 million and an expiration date of November 1, 2011.
Under the swap agreement, the Company pays the counterparty a variable rate
(LIBOR +2.42%) and receives a fixed rate (8 1/4%). Beginning on November 1, 2006
the counterparty has the option to terminate the swap early on any date
beginning on November 1, 2006, subject to an early termination fee ranging from
$4.125 million at November 1, 2006 to $0 on or after November 1, 2009. The early
termination dates and fees mirror the prepayment terms and prepayment penalties
included in the indenture related to the 8 1/4% Senior Subordinated Notes.

     The Company has documented and designated the interest rate swap as a hedge
of the fair value of a portion of the 8 1/4% Senior Subordinated Notes. Because
this swap meets the conditions to qualify for the "short cut" method of
assessing effectiveness under the provisions of SFAS 133, the change in the fair
value of the debt is assumed to equal the change in the fair value of the
interest rate swap. As such, there is no ineffectiveness assumed to exist
between the interest rate swap and the senior subordinated notes.

  INTEREST RATE SWAPS -- NON-HEDGE

     The swaps discussed below were not considered hedges for accounting
purposes during 2001.

     As a result of the Merger, the Company assumed three interest rate swap
agreements to convert fixed rate obligations to floating rate obligations. The
agreements were terminated in November 2001. During 2001, the Company recorded
$5.3 million in unrealized derivative gain for the change in fair value of
interest rate derivative contracts.

     Maturities of long-term debt for each of the five years following December
31, 2002 are as follows (in thousands):

<Table>
<S>                                                           <C>
YEAR ENDING DECEMBER 31,
2003........................................................  $     --
2004........................................................        --
2005........................................................        --
2006........................................................    80,000
2007........................................................   127,587
Thereafter..................................................   591,771
                                                              --------
                                                              $799,358
                                                              ========
</Table>

8.  STOCKHOLDERS' EQUITY

     On December 16, 2002, the Company closed the shelf offering of 11.5 million
shares of common stock at a price of $19.90 per share, which includes 1.5
million shares covered by an over-allotment option granted to, and which was
exercised by, the underwriters. The Company received net proceeds of
approximately $216 million from the sale of our common stock, which the Company
used to finance, in part, the Acquisition.

     On November 19, 2002, the Company completed the private equity offering of
3.125 million shares of its common stock to Spindrift Partners, L.P., Spindrift
Investors (Bermuda) L.P., Global Natural Resources III and Global Natural
Resources III L.P. at a net price to us of $16.00 per share for aggregate
proceeds of $50 million. On December 31, 2002, the Company filed the shelf
registration statement

                                       F-25
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

registering the resale by the selling stockholders from time to time of its
common stock issued in the private equity offering. The registration statement
was declared effective on January 7, 2003 by the SEC.

     On September 21, 2001, the Board of Directors authorized management to
repurchase up to $30 million of the Company's common stock. Through December 31,
2002, the Company has repurchased 30,000 shares of its common stock at an
average price of $13.61 per share including broker commissions.

     The Company's 6 1/2% convertible preferred stock has a liquidation
preference of $25 per share and is convertible at the option of the holder into
shares of the Company's common stock at an initial conversion rate of 0.465795
shares of common stock for each share of preferred stock, equivalent to a
conversion price of $11.64 per share of common stock. During 2002 and 2001, the
Company declared and paid dividends of $1.63 and $0.54 per share of preferred
stock, respectively.

9.  STOCK OPTIONS

     On March 24, 2000, the Company repurchased and cancelled 1,344,510 stock
options, representing all outstanding stock options at that date, from employees
and directors for approximately $3.4 million. The cost to repurchase the stock
options is included in stock compensation expense in the accompanying statement
of operations for the year ended December 31, 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.

     On October 17, 2000, the Westport Resources Directors' Stock Option Plan
and the Westport Resources Corporation Stock Option Plan (the "Predecessor
Plans") were merged into the Westport Resources Corporation 2000 Stock Incentive
Plan (the "Stock Option Plan"). The Stock Option Plan provides for issuance of
options to employees, officers and directors to purchase shares of common stock.
The aggregate number of shares of common stock that may be issued under the
Stock Option Plan is 6,232,484 shares. The exercise price, vesting and duration
of the options may vary and will be determined at the time of issuance.

     During 2002, options to purchase 638,099 shares of the Company's common
stock were granted under the Stock Option Plan at exercise prices between $17.18
and $20.47 per share, which reflected the estimated fair market value of the
shares at the date of grant. These options vest ratably over two or three years
from the date of grant and have a term of 10 years.

     In connection with the August 21, 2001 merger of Old Westport and Belco,
options previously issued by Belco were converted into options to purchase
788,194 shares of Westport common stock at exercise prices between $11.82 and
$70.30 per share. These exercise prices reflect the estimated fair market value
of the shares on August 21, 2001, after converting the Belco options into the
existing Westport plan using a .4125 rate to account for the reverse stock split
which was consummated under the merger agreement. Since Belco options converted
into options to purchase Westport common stock were fully vested, the fair value
of Westport options issued upon conversion was included in the purchase price of
the Merger, in accordance with FASB Interpretation No. 44 (see Note 2 -- Belco
Merger). The fair value of Westport options issued upon conversion of Belco
options was determined using the Black-Scholes option pricing model. Also during
2001, options to purchase 690,562 shares of the Company's common stock were
granted under the Stock Option Plan at exercise prices between $15.90 and $31.07
per share, which reflected the estimated fair market value of the shares at the
date of grant. The options vest ratably over two or three years from the date of
grant and have a term of 10 years.

     Options to purchase 2,110,880 shares of the Company's common stock were
granted during 2000 under the Stock Option Plan at exercise prices between
$10.85 and $17.63 per share, which reflected the estimated fair market value of
the shares at the date of grant. Of the 2,110,880 options granted in 2000,
1,344,510 options are deemed to be replacement options (the "Replacement
Options") for those options repurchased by the Company on March 24, 2000.

                                       F-26
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     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. Under provisions of
the Interpretation, the Company is 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 the Company 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. As of December 31,
2002, 979,223 of the Replacement Options were still outstanding, which resulted
in $2.1 million, $0.4 million and $4.3 million of compensation costs recorded in
2000, 2001 and 2002 respectively.

     A summary of the status of the Company's Stock Option Plans as of December
31, 2002, 2001 and 2000 and changes during the years ended December 31, 2002,
2001, and 2000 are included below:

<Table>
<Caption>
                                                                            WEIGHTED
                                                                SHARES      AVERAGE
                                                                 UNDER      EXERCISE
                                                              OPTION PLAN    PRICE
                                                              -----------   --------
<S>                                                           <C>           <C>
Balance at December 31, 1999................................   1,344,510     $ 8.29
  Options repurchased.......................................  (1,344,510)     12.43
  Options granted...........................................   2,110,880      12.61
  Options forfeited.........................................     (44,421)     10.85
  Options exercised.........................................     (13,018)     10.85
                                                              ----------     ------
Balance at December 31, 2000................................   2,053,441      12.61
  Options converted from Belco..............................     788,194      28.61
  Options granted...........................................     690,562      21.32
  Options forfeited.........................................    (276,683)     27.75
  Options exercised.........................................     (49,675)     11.59
                                                              ----------     ------
Balance at December 31, 2001................................   3,205,839      17.13
  Options granted...........................................     638,099      18.23
  Options forfeited.........................................    (260,861)     31.02
  Options exercised.........................................    (105,064)     12.85
                                                              ----------     ------
Balance at December 31, 2002................................   3,478,013     $16.42
                                                              ==========     ======
Options exercisable at December 31, 2000....................      29,516     $10.85
                                                              ==========     ======
Options exercisable at December 31, 2001....................   1,272,065     $19.36
                                                              ==========     ======
Options exercisable at December 31, 2002....................   1,812,379     $15.97
                                                              ==========     ======
</Table>

                                       F-27
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     The following table summarizes information about stock options outstanding
at December 31, 2002.

<Table>
<Caption>
                                          OPTIONS OUTSTANDING
                                   ----------------------------------   OPTIONS EXERCISABLE
                                                WEIGHTED                --------------------
                                                 AVERAGE     WEIGHTED               WEIGHTED
                                                REMAINING    AVERAGE                AVERAGE
RANGE OF                           NUMBER OF   CONTRACTUAL   EXERCISE   NUMBER OF   EXERCISE
EXERCISE PRICE                      OPTIONS    LIFE (YRS)     PRICE      OPTIONS     PRICE
--------------                     ---------   -----------   --------   ---------   --------
<S>                                <C>         <C>           <C>        <C>         <C>
$ 7.03-$14.06....................  1,459,138       7.3        $10.92      998,171    $10.94
$14.07-$21.09....................  1,726,933       8.5        $18.64      578,677    $18.46
$21.10-$28.12....................    161,166       6.9        $23.31      148,168    $23.32
$28.13-$42.17....................     68,500       8.4        $30.74       25,087    $30.77
$42.18-$49.21....................     14,020       4.1        $46.81       14,020    $46.81
$49.22-$63.26....................     44,957       4.9        $49.77       44,957    $49.77
$63.27-$70.30....................      3,299       3.4        $70.02        3,299    $70.02
                                   ---------       ---        ------    ---------    ------
                                   3,478,013       7.9        $16.42    1,812,379    $15.97
                                   =========       ===        ======    =========    ======
</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 income would have been decreased and the net loss would have been
increased to the pro forma amounts indicated below:

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31,
                                                         -------------------------------------
                                                            2002          2001         2000
                                                         -----------   ----------   ----------
                                                         (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                      <C>           <C>          <C>
Net income (loss)
  As reported..........................................   $(28,566)     $49,821      $43,536
  Pro forma............................................    (36,918)      45,148       41,885
Basic net income (loss) per common share
  As reported..........................................   $  (0.63)     $  1.11      $  1.54
  Pro forma............................................      (0.79)        1.00         1.51
Diluted net income (loss) per common share
  As reported..........................................   $  (0.63)     $  1.09      $  1.52
  Pro forma............................................      (0.79)        0.99         1.49
</Table>

     The weighted average fair value of options granted during the years ended
December 31, 2002, 2001 and 2000, calculated using the Black-Scholes option
pricing model was $8.46, $8.88 and $5.44, respectively. The fair value of each
option granted is estimated with the following weighted average assumptions for
grants in 2002, 2001 and 2000: risk-free interest rate of 1.67%, 3.89% and
6.25%, respectively; no dividend yields; expected volatility of 52.22%, 40.74%
and 38.34%, respectively; and expected lives of 5 years.

10. RESTRICTED STOCK AWARDS

     The Company issued 36,550 shares of common stock as restricted stock awards
pursuant to the Company's 2000 Stock Incentive Plan to certain employees during
2001. The shares are restricted for various periods ranging from one to three
years after the date of grant. As of December 31, 2002

                                       F-28
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

21,550 shares had vested. During the years ended December 31, 2002 and 2001,
compensation expense of $0.3 million and $0.3 million, respectively, was
recorded as a result of the issuance.

11. MAJOR PURCHASERS

     The following purchasers accounted for 10% or more of the Company's oil and
gas sales for the years ended December 31, 2002, 2001 and 2000:

<Table>
<Caption>
                                                              2002   2001   2000
                                                              ----   ----   ----
<S>                                                           <C>    <C>    <C>
Dynegy Inc. ................................................   --     23%    23%
Conoco Inc. ................................................   10%    --     14%
EOTT Energy Corporation.....................................   --     --     13%
</Table>

12.  COMMITMENTS AND CONTINGENCIES

     At December 31, 2002, the Company has leases covering office space and
copiers under noncancelable agreements which begin to expire in November 2003.
The minimum annual lease payments under noncancelable operating leases are as
follows (in thousands):

<Table>
<S>                                                           <C>
YEAR ENDING DECEMBER 31
2003........................................................      $1,196
2004........................................................         885
2005........................................................       1,177
2006........................................................       1,256
2007........................................................       1,160
Thereafter..................................................         522
                                                                  ------
                                                                  $6,196
                                                                  ======
</Table>

     Rent expense for the years ended December 31, 2002, 2001 and 2000 was
approximately $1,439,000, $954,000 and $820,000, respectively.

     The Company entered into employment agreements on April 1, 2002 with its
chief executive officer and president, which provide for annual base salaries of
$382,000 and $264,000, respectively, subject to annual adjustments through May
31, 2005. 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 in 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.

     Following the Merger, the Company entered into retention agreements with
its executive officers. The retention agreements set forth the terms and
conditions of the officers' compensation in the event of termination of their
employment following a change in control, as defined in the agreements, within
five years of the date of such retention agreements. Each agreement
automatically expires if a change in control has not occurred within the
five-year period, and may be renewed for successive one-year periods by written
agreement of the parties. If a termination following a change in control occurs
within the specified period, other than a termination for cause or with good
reason, as defined in the agreement, the terminated person will be entitled to
all earned and accrued compensation and benefits plus severance compensation
equal to a stated percentage of the sum of their respective base salary and
average bonus for three prior years, plus the amount of any excise tax imposed
on such severance payment. In addition, all equity incentive awards become
immediately vested.

                                       F-29
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

     Westport Oil and Gas Company, L.P., the Company's wholly-owned subsidiary,
is a defendant in a case brought in July 2001 against its predecessor, Belco
Energy Corp., in the district court of Sweetwater County, Wyoming. The complaint
seeks damages on behalf of a purported class of royalty owners for alleged
improper deduction, valuation and reporting under the Wyoming Royalty Payment
Act in connection with royalty payments made by Belco on production from wells
it operates in the Moxa Arch area of the Green River Basin. Plaintiffs have
advised Westport that they calculate the amount of damages allegedly owed by
Belco as approximately $1,165,000, which includes attorneys fees and litigation
costs. Westport has denied liability for any of these damages and believes that
it has valid defenses to plaintiffs' claims. Class certification and discovery
have been stayed pending the decision by the Wyoming Supreme Court in a case
involving unrelated parties that may have a bearing on this case and other
similar cases filed by plaintiffs against other oil and gas industry operators
in the Green River Basin. Settlement discussions have occurred with plaintiffs
and are ongoing. The Company believes that the potential liability with respect
to such proceedings is not material in the aggregate to the Company's financial
position, results of operations or cash flows. Accordingly, the Company has not
established a reserve for loss in connection with this proceeding.

     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, results of operations
or cash flows.

13.  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 75%
of each participant's contributions up to 6% of the participant's compensation.
The Company contributed $610,000, $400,000 and $155,000, for the years ended
December 31, 2002, 2001 and 2000, respectively.

14.  RELATED PARTY TRANSACTIONS

     Prior to the Merger, Belco entered into a substantial portion of its
natural gas and crude oil commodity swap agreements and option agreements with
Enron North America Corp., ("ENA"), formerly known as Enron Capital & Trade
Resources Corp., a wholly owned subsidiary of Enron Corp. Mr. Robert A. Belfer,
one of the Company's directors, was a member of the Board of Directors of Enron
Corp. and was the CEO of Belco at the time these transactions were entered into.
These agreements were entered into in the ordinary course of business of Belco
and on terms that the Company believes were no less favorable to Belco than the
terms of similar arrangements with third parties. Pursuant to the terms of these
agreements the Company paid ENA a net amount of approximately $5.4 million from
the date of the Merger, August 21, 2001, through December 31, 2001.

     On November 29, 2001, the Company terminated all commodity derivative
contracts with ENA. The Company exercised its rights pursuant to the early
termination provisions of such contracts as a result of ENA's bankruptcy filing
and related events. The Company believes that it had the legal right to
terminate these agreements, but ENA may challenge the termination in bankruptcy
court. Applying the mark-to-market and setoff methodology of the derivative
contracts with ENA, the Company has calculated that it

                                       F-30
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

owed ENA a net amount of $204,000 for all derivative transactions that were
outstanding under the ENA contracts. Although the Company believes this
methodology was correct, it is possible that ENA will challenge such
calculations and claim larger amounts owed.

  OFFICE LEASE

     Belco paid Robert A. Belfer, former Chairman of the Board and Chief
Executive Officer of Belco and one of the Company's directors, a fee of $172,172
during 2001 for office space and services provided through such office from
January 2001 through August 2001. After Westport's merger with and into Belco,
the Company paid a fee of $88,908 to Mr. Belfer for the office space from
September 2001 through January 2002. The fee is based on the actual cost of such
office space pro-rated to the amount utilized in the Company's operations. The
Company believes the fee compared favorably to the terms which might have been
available from a non-affiliated party. The Company has not paid a fee to Mr.
Belfer for office space since January 31, 2002 and does not intend to use this
office space in the future.

  DOMINICK GOLIO

     Pursuant to federal income tax laws, recipients of awards of restricted
stock under Belco's 1996 Stock Incentive Plan are deemed to have income equal to
the fair market value of the vested shares of the Company's common stock on the
date of vesting. As of December 31, 2001, Dominick J. Golio was indebted to the
Company in the amount of $69,320, representing federal income taxes paid by the
Company on behalf of Dominick J. Golio that arose pursuant to the vesting of Mr.
Golio's restricted stock. Upon Mr. Golio's termination in March 2002, the amount
of his indebtedness to the Company was satisfied in full out of his severance
compensation. The Company did not charge interest on this indebtedness.

     In October 2001, the Company entered into a letter agreement with Dominick
J. Golio whereby Mr. Golio would, after cessation of his employment, continue to
assist the Company in certain pending litigation. As compensation, the Company
agreed to pay Mr. Golio 7 1/2% of the Company's total net recovery, if any, in
the litigation. The suit was settled in September 2002. On December 16, 2002,
Mr. Golio received a cash payment of $156,334 and agreed to receive severance
benefits with an aggregate cash value of $58,936 in full satisfaction of the
amounts owed to him under the letter agreement. The amount of $58,936 will
become due and payable as provided in the agreement with Mr. Golio. Upon payment
of severance benefits in the aggregate amount of $58,936, as they become due and
payable, the Company will have no additional obligations to Mr. Golio.

15.  SEGMENT INFORMATION:

     The Company operates in four geographic divisions: Northern (Rocky
Mountains); Southern (Permian Basin, Mid-Continent and Gulf Coast); Western
(Uinta Basin which is currently focused on the recently acquired properties in
Utah) and Gulf of Mexico (offshore). Amounts presented below for Western only
represent fifteen days of operations in 2002. All four areas are engaged in the
production, development, acquisition and exploration of oil and natural gas
properties. The Company evaluates segment performance based on the profit or
loss from operations before income taxes. Corporate general

                                       F-31
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and administrative expenses are unallocated in 2001 and 2000. Consolidated and
segment financial information is as follows:


<Table>
<Caption>
                                                                    GULF OF    CORPORATE &
                                   NORTHERN   SOUTHERN   WESTERN     MEXICO    UNALLOCATED   CONSOLIDATED
                                   --------   --------   --------   --------   -----------   ------------
<S>                                <C>        <C>        <C>        <C>        <C>           <C>
2002
Revenues(1)......................  $125,863   $163,842   $  1,857   $135,184    $(27,178)     $  399,568
DD&A.............................    45,210     77,844        791     78,813         435         203,093
Impairment of proved
  properties.....................    12,231      6,118         --      1,351          --          19,700
Impairment of unproved
  properties.....................     3,847      2,109         --      4,005          --           9,961
Profit (loss)....................    12,571      8,160        292     (3,740)    (32,339)        (15,056)
Assets(2)........................   395,375    894,420    506,618    296,330     140,798       2,233,541
Expenditures for assets, net.....    72,074    162,706    510,916     80,220       1,586         827,502
2001
Revenues(1)......................    92,583     73,526         --    153,128      29,623         348,860
DD&A.............................    26,116     34,108         --     62,947         888         124,059
Impairment of proved
  properties.....................     8,811         --         --        612          --           9,423
Impairment of unproved
  properties.....................        24          9         --      6,941          --           6,974
Profit (loss)....................    22,064     12,305         --     33,197      17,249          84,815
Assets(2)........................   418,817    789,429         --    305,372      90,598       1,604,216
Expenditures for assets, net.....    40,217     38,195         --    115,088         744         194,244
2000
Revenues(1)......................    91,416     38,715         --    117,668     (25,366)        222,433
DD&A.............................    15,220      8,950         --     40,431         255          64,856
Impairment of proved
  properties.....................     1,713        257         --        941          --           2,911
Impairment of unproved
  properties.....................     2,884        722         --      1,518          --           5,124
Profit (loss)....................    43,885     18,826         --     49,348     (36,450)         75,609
Assets(2)........................   130,530     87,189         --    296,412      37,700         551,831
Expenditures for assets, net.....    14,661      5,620         --    124,936         869         146,086
</Table>


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

(1) Corporate and unallocated revenues consist of hedge settlements, non-hedge
    settlements and non-hedge change in fair value of derivatives.

(2) Corporate and unallocated assets include $16.5 million, $25.5 million and
    $11.6 million of joint interest billing receivables at December 31, 2002,
    2001 and 2000. Because the Company tracks its joint interest receivables by
    joint interest partner and not by property, the Company is unable to
    allocate joint interest receivables to its three divisions.

16.  CONDENSED CONSOLIDATED FINANCIAL STATEMENTS OF SUBSIDIARY GUARANTORS:

     On November 5, 2001 the Company completed a private placement of the 8 1/4%
Senior Subordinated Notes due 2011 (see Note 8). The 8 1/4% Senior Subordinated
Notes are fully and unconditionally guaranteed, jointly and severally, on a
senior subordinated unsecured basis by the following wholly-owned subsidiaries
of Westport: Westport Finance Co., Jerry Chambers Exploration Company, Westport
Argentina LLC, Westport Canada LLC, Westport Oil and Gas Company, L.P., Horse
Creek Trading & Compression Company LLC, Westport Field Services, LLC, Westport
Overriding Royalty LLC, WHG, Inc. and WHL, Inc. (collectively, the "Subsidiary
Guarantors"). The guarantees of the Subsidiary Guarantors are subordinated to
senior debt of the Subsidiary Guarantors.

     Presented below are condensed consolidating financial statements for
Westport and the Subsidiary Guarantors.

                                       F-32
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                     CONDENSED CONSOLIDATING BALANCE SHEET
                               DECEMBER 31, 2002

<Table>
<Caption>
                                                         PARENT     SUBSIDIARY
                                                        COMPANY     GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                                       ----------   ----------   ------------   ------------
                                                                          (IN THOUSANDS)
<S>                                                    <C>          <C>          <C>            <C>
                                                   ASSETS
Current Assets:
  Cash and cash equivalents..........................  $    2,581   $   40,180   $        --     $   42,761
  Accounts receivable, net...........................      27,880       45,669            --         73,549
  Intercompany receivable............................   1,475,393           --    (1,475,393)            --
  Derivative assets..................................      14,861           --            --         14,861
  Prepaid expenses...................................       7,922        5,436            --         13,358
                                                       ----------   ----------   -----------     ----------
         Total current assets........................   1,528,637       91,285    (1,475,393)       144,529
                                                       ----------   ----------   -----------     ----------
Property and equipment, at cost:
  Oil and gas properties, successful efforts method:
    Proved properties................................     339,947    1,837,709            --      2,177,656
    Unproved properties..............................      29,252       75,178            --        104,430
  Building and other office furniture and
    equipment........................................         620        9,066            --          9,686
                                                       ----------   ----------   -----------     ----------
                                                          369,819    1,921,953            --      2,291,772
  Less accumulated depletion, depreciation and
    amortization.....................................    (131,946)    (353,383)           --       (485,329)
                                                       ----------   ----------   -----------     ----------
         Net property and equipment..................     237,873    1,568,570            --      1,806,443
                                                       ----------   ----------   -----------     ----------
Other Assets:
  Long-term derivative assets........................      14,824           --            --         14,824
  Goodwill...........................................          --      246,712            --        246,712
  Other assets.......................................      21,033           --            --         21,033
                                                       ----------   ----------   -----------     ----------
         Total other assets..........................      35,857      246,712            --        282,569
                                                       ----------   ----------   -----------     ----------
         Total assets................................  $1,802,367   $1,906,567   $(1,475,393)    $2,233,541
                                                       ==========   ==========   ===========     ==========
                                    LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
  Accounts payable...................................  $   15,301   $   35,857   $        --     $   51,158
  Accrued expenses...................................      23,354       15,855            --         39,209
  Ad valorem taxes payable...........................          (2)       8,990            --          8,988
  Intercompany payable...............................          --    1,475,393    (1,475,393)            --
  Derivative liabilities.............................      56,156           --            --         56,156
  Income taxes payable...............................          --           86            --             86
                                                       ----------   ----------   -----------     ----------
         Total current liabilities...................      94,809    1,536,181    (1,475,393)       155,597
                                                       ----------   ----------   -----------     ----------
Long-term debt.......................................     799,358           --            --        799,358
Deferred income taxes................................     (13,361)     137,891            --        124,530
Long-term derivative liabilities.....................      21,305           --            --         21,305
Other liabilities....................................          --          745            --            745
                                                       ----------   ----------   -----------     ----------
         Total liabilities...........................     902,111    1,674,817    (1,475,393)     1,101,535
                                                       ----------   ----------   -----------     ----------
Stockholders' equity
  Preferred stock....................................          29           --            --             29
  Common stock.......................................         668            3            (3)           668
  Additional paid-in capital.........................     951,189      199,153             3      1,150,345
  Treasury stock.....................................        (469)          --            --           (469)
  Retained earnings..................................     (32,753)      32,755            --              2
  Accumulated other comprehensive income.............     (18,408)        (161)           --        (18,569)
                                                       ----------   ----------   -----------     ----------
         Total stockholders' equity..................     900,256      231,750            --      1,132,006
                                                       ----------   ----------   -----------     ----------
         Total liabilities and stockholders'
           equity....................................  $1,802,367   $1,906,567   $(1,475,393)    $2,233,541
                                                       ==========   ==========   ===========     ==========
</Table>

                                       F-33
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
                      FOR THE YEAR ENDED DECEMBER 31, 2002


<Table>
<Caption>
                                                   PARENT    SUBSIDIARY
                                                  COMPANY    GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                                  --------   ----------   ------------   ------------
                                                                    (IN THOUSANDS)
<S>                                               <C>        <C>          <C>            <C>
Operating revenues:
  Oil and natural gas sales.....................  $ 82,136    $346,294      $     --       $428,430
  Hedge settlements.............................    (1,276)         --            --         (1,276)
  Non-hedge settlements.........................       822          --            --            822
  Non-hedge change in fair value of
     derivatives................................   (26,723)         --            --        (26,723)
  Gain (loss) on sale of operating assets,
     net........................................       276      (1,961)           --         (1,685)
                                                  --------    --------      --------       --------
          Net revenues..........................    55,235     344,333            --        399,568
                                                  --------    --------      --------       --------
Operating expenses:
  Lease operating expense.......................    12,748      76,580            --         89,328
  Production taxes..............................         5      23,949            --         23,954
  Transportation costs..........................       317       7,644            --          7,961
  Exploration...................................    21,689      10,701            --         32,390
  Depletion, depreciation and amortization......    48,847     154,246            --        203,093
  Impairment of proved properties...............        --      19,700            --         19,700
  Impairment of unproved properties.............     3,046       6,915            --          9,961
  Stock compensation expense....................     4,608          --            --          4,608
  General and administrative....................     6,046      17,583            --         23,629
                                                  --------    --------      --------       --------
          Total operating expenses..............    97,306     317,318            --        414,624
                                                  --------    --------      --------       --------
          Operating income......................   (42,071)     27,015            --        (15,056)
                                                  --------    --------      --------       --------
Other income (expense):
  Interest expense..............................   (34,607)       (229)           --        (34,836)
  Interest income...............................       172         374            --            546
  Change in interest rate swap fair value.......        --         226            --            226
  Other.........................................       579         423            --          1,002
                                                  --------    --------      --------       --------
Income (loss) before income taxes...............   (75,927)     27,809            --        (48,118)
                                                  --------    --------      --------       --------
Provision for income taxes:
  Current.......................................        --       2,094            --          2,094
  Deferred......................................    27,609     (10,151)           --         17,458
                                                  --------    --------      --------       --------
          Total provision for income taxes......    27,609      (8,057)           --         19,552
                                                  --------    --------      --------       --------
Net income (loss)...............................   (48,318)     19,752            --        (28,566)
Preferred stock dividends.......................     4,762          --            --          4,762
                                                  --------    --------      --------       --------
Net income (loss) available to common
  stockholders..................................  $(53,080)   $ 19,752      $     --       $(33,328)
                                                  ========    ========      ========       ========
</Table>


                                       F-34
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
                      FOR THE YEAR ENDED DECEMBER 31, 2002

<Table>
<Caption>
                                                 PARENT     SUBSIDIARY
                                                 COMPANY    GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                                ---------   ----------   ------------   ------------
                                                                   (IN THOUSANDS)
<S>                                             <C>         <C>          <C>            <C>
Cash flows from operating activities:
  Net income (loss)...........................  $ (48,318)  $  19,752     $      --      $ (28,566)
  Adjustments to reconcile net income (loss)
     to net cash provided by operating
     activities:
     Depletion, depreciation and
       amortization...........................     48,847     154,246            --        203,093
     Exploration dry hole costs...............     13,955       5,591            --         19,546
     Impairment of proved properties..........         --      19,700            --         19,700
     Impairment of unproved properties........      3,046       6,915            --          9,961
     Deferred income taxes....................    (27,609)     10,151            --        (17,458)
     Stock compensation expense...............      4,608          --            --          4,608
     Change in derivative fair value..........     27,475          --            --         27,475
     Amortization of finance fees.............      2,438          --            --          2,438
     Changes in asset and liabilities, net of
       effects of loss (gain) on sale of
       assets.................................       (276)      1,961            --          1,685
     Other....................................       (274)         --            --           (274)
     Changes in asset and liabilities, net of
       effects of acquisitions:
       Decrease (increase) in accounts
          receivable..........................     (9,194)      6,285            --         (2,909)
       Decrease in prepaid expenses...........     (5,575)        544            --         (5,031)
       Decrease in net derivative
          liabilities.........................    (10,388)         --            --        (10,388)
       Increase (decrease) in accounts
          payable.............................     (3,405)     (3,168)           --         (6,573)
       Decrease in ad valorem taxes payable...         (2)       (849)           --           (851)
       Increase in income taxes payable.......        248        (725)           --           (477)
       Increase (decrease) in accrued
          expenses............................      2,782       5,323            --          8,105
       Decrease in other liabilities..........         --        (887)           --           (887)
                                                ---------   ---------     ---------      ---------
          Net cash provided by operating
            activities........................     (1,642)    224,839            --        223,197
                                                ---------   ---------     ---------      ---------
Cash flows from investing activities:
  Additions to property and equipment.........    (68,928)    (78,684)           --       (147,612)
  Proceeds from sales of assets...............        750      12,561            --         13,311
  Increase in intercompany receivable.........   (547,479)         --       547,479             --
  Other acquisitions..........................       (328)   (679,562)           --       (679,890)
  Other.......................................         --          28            --             28
                                                ---------   ---------     ---------      ---------
          Net cash used in investing
            activities........................   (615,985)   (745,657)      547,479       (814,163)
                                                ---------   ---------     ---------      ---------
Cash flows from financing activities:
  Proceeds from issuance of common stock......    267,787          --            --        267,787
  Repurchase of common stock..................        (61)         --            --            (61)
  Proceeds from issuance of long-term debt....    639,000          --            --        639,000
  Repayment of long-term debt.................   (285,000)         --            --       (285,000)
  Preferred stock dividend....................     (4,762)         --            --         (4,762)
  Gain in interest rate swap cancellation.....      3,705          --            --          3,705
  Financing fees..............................    (14,273)         --            --        (14,273)
  Increase in intercompany payable............         --     547,479      (547,479)            --
                                                ---------   ---------     ---------      ---------
          Net cash provided by (used in)
            financing activities..............    606,396     547,479      (547,479)       606,396
                                                ---------   ---------     ---------      ---------
Net increase in cash and cash equivalents.....    (11,231)     26,661            --         15,430
Effect of exchange rate changes on cash.......         --        (253)           --           (253)
Cash and cash equivalents, beginning of
  year........................................     13,812      13,772            --         27,584
                                                ---------   ---------     ---------      ---------
Cash and cash equivalents, end of year........  $   2,581   $  40,180     $      --      $  42,761
                                                =========   =========     =========      =========
</Table>

                                       F-35
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                     CONDENSED CONSOLIDATING BALANCE SHEET
                               DECEMBER 31, 2001

<Table>
<Caption>
                                                 PARENT     SUBSIDIARY
                                                COMPANY     GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                               ----------   ----------   ------------   ------------
                                                                  (IN THOUSANDS)
<S>                                            <C>          <C>          <C>            <C>
                                               ASSETS
Current Assets:
  Cash and cash equivalents..................  $   13,812   $   13,772    $      --      $   27,584
  Accounts receivable, net...................      18,687       43,121           --          61,808
  Intercompany receivable....................     919,727           --     (919,727)             --
  Derivative assets..........................          --        7,832           --           7,832
  Prepaid expenses...........................       2,345        3,129           --           5,474
                                               ----------   ----------    ---------      ----------
       Total current assets..................     954,571       67,854     (919,727)        102,698
                                               ----------   ----------    ---------      ----------
Property and equipment, at cost:
  Oil and gas properties, successful efforts
     method:
     Proved properties.......................     281,868    1,164,463           --       1,446,331
     Unproved properties.....................      23,978       81,561           --         105,539
  Office building, furniture and equipment...         487        7,612           --           8,099
                                               ----------   ----------    ---------      ----------
                                                  306,333    1,253,636           --       1,559,969
Less accumulated depletion, depreciation and
  amortization...............................     (83,016)    (200,749)          --        (283,765)
                                               ----------   ----------    ---------      ----------
       Net property and equipment............     223,317    1,052,887           --       1,276,204
                                               ----------   ----------    ---------      ----------
Other assets:
  Long-term derivative assets................          --          612           --             612
  Goodwill...................................          --      214,844           --         214,844
  Other assets...............................       9,830           28           --           9,858
                                               ----------   ----------    ---------      ----------
       Total other assets....................       9,830      215,484           --         225,314
                                               ----------   ----------    ---------      ----------
       Total assets..........................  $1,187,718   $1,336,225    $(919,727)     $1,604,216
                                               ==========   ==========    =========      ==========
                                LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
  Accounts payable...........................  $   14,254   $   33,647    $      --      $   47,901
  Accrued expenses...........................       8,840       21,454           --          30,294
  Ad valorem taxes payable...................          --        6,930           --           6,930
  Intercompany payable.......................          --      919,727     (919,727)             --
  Derivative liabilities.....................          --        3,289           --           3,289
  Income taxes payable.......................        (131)         681           --             550
  Other current liabilities..................          --          369           --             369
                                               ----------   ----------    ---------      ----------
       Total current liabilities.............      22,963      986,097     (919,727)         89,333
                                               ----------   ----------    ---------      ----------
Long-term debt...............................     429,224           --           --         429,224
Deferred income taxes........................      31,053      126,952           --         158,005
Long-term derivative liabilities.............       5,205          751           --           5,956
Other liabilities............................          --        1,402           --           1,402
                                               ----------   ----------    ---------      ----------
       Total liabilities.....................     488,445    1,115,202     (919,727)        683,920
                                               ----------   ----------    ---------      ----------
Stockholders' equity:
  Preferred stock............................          29           --           --              29
  Common stock...............................         521            3           (3)            521
  Additional paid-in capital.................     678,804      199,153            3         877,960
  Treasury stock.............................        (408)          --           --            (408)
  Retained earnings (accumulated deficit)....      20,327       13,003           --          33,330
  Accumulated other comprehensive income.....          --        8,864           --           8,864
                                               ----------   ----------    ---------      ----------
       Total stockholders' equity............     699,273      221,023           --         920,296
                                               ----------   ----------    ---------      ----------
       Total liabilities and stockholders'
          equity.............................  $1,187,718   $1,336,225    $(919,727)     $1,604,216
                                               ==========   ==========    =========      ==========
</Table>

                                       F-36
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
                      FOR THE YEAR ENDED DECEMBER 31, 2001

<Table>
<Caption>
                                                   PARENT    SUBSIDIARY
                                                   COMPANY   GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                                   -------   ----------   ------------   ------------
                                                                     (IN THOUSANDS)
<S>                                                <C>       <C>          <C>            <C>
Operating revenues:
  Oil and natural gas sales......................  $90,954    $226,324      $     --       $317,278
  Hedge settlements..............................       --       2,091            --          2,091
  Non-hedge settlements..........................       --      15,300            --         15,300
  Non-hedge change in fair value of
     derivatives.................................       --      14,323            --         14,323
  Gain (loss) on sale of operating assets, net...     (304)        172            --           (132)
                                                   -------    --------      --------       --------
     Net revenues................................   90,650     258,210            --        348,860
Operating expenses:
  Lease operating expense........................    7,879      47,436            --         55,315
  Production taxes...............................        8      13,399            --         13,407
  Transportation costs...........................      421       4,736            --          5,157
  Exploration....................................   24,393       6,920            --         31,313
  Depletion, depreciation and amortization.......   43,044      81,015            --        124,059
  Impairment of proved properties................      612       8,811            --          9,423
  Impairment of unproved properties..............    5,562       1,412            --          6,974
  Stock compensation expense.....................      719          --            --            719
  General and administrative.....................    6,410      11,268            --         17,678
                                                   -------    --------      --------       --------
     Total operating expenses....................   89,048     174,997            --        264,045
                                                   -------    --------      --------       --------
     Operating income............................    1,602      83,213            --         84,815
                                                   -------    --------      --------       --------
Other income (expense):
  Interest expense...............................   (6,990)     (6,206)           --        (13,196)
  Interest income................................    1,159         509            --          1,668
  Change in interest rate swap fair value........       --       4,960                        4,960
  Other..........................................      163          48            --            211
                                                   -------    --------      --------       --------
Income (loss) before income taxes................   (4,066)     82,524            --         78,458
                                                   -------    --------      --------       --------
Provision for income taxes:
  Current........................................       --      (2,006)           --         (2,006)
  Deferred.......................................    1,547     (28,178)           --        (26,631)
                                                   -------    --------      --------       --------
     Total provision for income taxes............    1,547     (30,184)           --        (28,637)
                                                   -------    --------      --------       --------
Net income (loss)................................   (2,519)     52,340            --         49,821
Preferred stock dividends........................    1,587          --            --          1,587
                                                   -------    --------      --------       --------
Net income (loss) available to common
  stockholders...................................  $(4,106)   $ 52,340      $     --       $ 48,234
                                                   =======    ========      ========       ========
</Table>

                                       F-37
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
                      FOR THE YEAR ENDED DECEMBER 31, 2001

<Table>
<Caption>
                                                 PARENT     SUBSIDIARY
                                                 COMPANY    GUARANTORS    ELIMINATIONS   CONSOLIDATED
                                                ---------   -----------   ------------   ------------
                                                                   (IN THOUSANDS)
<S>                                             <C>         <C>           <C>            <C>
Cash flows from operating activities:
  Net income..................................  $  (2,519)   $  52,340      $     --      $  49,821
  Adjustments to reconcile net income to net
     cash provided by operating activities:
     Depletion, depreciation and
       amortization...........................     43,044       81,015            --        124,059
     Exploration dry hole costs...............     14,183        5,090            --         19,273
     Impairment of proved properties..........        612        8,811            --          9,423
     Impairment of unproved properties........      5,562        1,412            --          6,974
     Stock compensation expense...............        719           --            --            719
     Change in derivative fair value..........         --      (19,283)           --        (19,283)
     Loss (gain) on sale of assets............        304         (172)           --            132
     Deferred income taxes....................     (1,547)      28,178            --         26,631
     Amortization of finance fees.............        323          112            --            435
     Changes in asset and liabilities, net of
       effects of acquisitions:
       Decrease (increase) in accounts
          receivable..........................     (4,283)      14,409            --         10,126
       Decrease in prepaid expenses...........        797          254            --          1,051
       Decrease in net derivative
          liabilities.........................         --      (18,285)           --        (18,285)
       Increase (decrease) in accounts
          payable.............................      7,193      (13,433)           --         (6,240)
       Increase (decrease) in accrued
          expenses............................     (5,982)      (2,492)           --         (8,474)
       Increase in ad valorem taxes payable...         --       (1,130)           --         (1,130)
       Increase in income taxes payable.......         --          301            --            301
       Decrease in other liabilities..........         --         (260)           --           (260)
                                                ---------    ---------      --------      ---------
          Net cash provided by operating
            activities........................     58,406      136,867            --        195,273
                                                ---------    ---------      --------      ---------
Cash flows from investing activities:
  Additions to property and equipment.........    (76,083)    (111,842)           --       (187,925)
  Proceeds from sales of assets...............        161        5,375            --          5,536
  Other acquisitions..........................         --       (6,319)           --         (6,319)
  Increase in intercompany receivable.........     18,340           --       (18,340)            --
  Other.......................................         --           22            --             22
                                                ---------    ---------      --------      ---------
          Net cash used in investing
            activities........................    (57,582)    (112,764)      (18,340)      (188,686)
                                                ---------    ---------      --------      ---------
Cash flows from financing activities:
  Proceeds from issuance of common stock......        576           --            --            576
  Repurchase of common stock..................       (408)          --            --           (408)
  Proceeds from issuance of long-term debt....    590,000           --            --        590,000
  Repayment of long-term debt.................   (577,898)         313            --       (577,585)
  Preferred stock dividend....................     (1,587)          --            --         (1,587)
  Financing fees..............................    (10,153)          --            --        (10,153)
  Increase in intercompany payable............         --      (18,340)       18,340             --
                                                ---------    ---------      --------      ---------
          Net cash provided by (used in)
            financing activities..............        530      (18,027)       18,340            843
                                                ---------    ---------      --------      ---------
Net increase in cash and cash equivalents.....      1,354        6,076            --          7,430
Cash and cash equivalents, beginning of
  year........................................     12,458        7,696            --         20,154
                                                ---------    ---------      --------      ---------
Cash and cash equivalents, end of year........  $  13,812    $  13,772      $     --      $  27,584
                                                =========    =========      ========      =========
</Table>

                                       F-38
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
                      FOR THE YEAR ENDED DECEMBER 31, 2000

<Table>
<Caption>
                                                   PARENT    SUBSIDIARY
                                                  COMPANY    GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                                  --------   ----------   ------------   ------------
                                                                    (IN THOUSANDS)
<S>                                               <C>        <C>          <C>            <C>
Operating revenues:
  Oil and natural gas sales.....................  $ 95,336    $149,333      $     --       $244,669
  Hedge settlements.............................        --     (24,627)           --        (24,627)
  Non-hedge change in fair value of
     derivatives................................        --        (739)           --           (739)
  Gain (loss) on sale of operating assets,
     net........................................        --       3,130            --          3,130
                                                  --------    --------      --------       --------
     Net revenues...............................    95,336     127,097            --        222,433
Operating expenses:
  Lease operating expense.......................     6,530      27,867            --         34,397
  Production taxes..............................        15      10,616            --         10,631
  Transportation costs..........................       384       2,650            --          3,034
  Exploration...................................     6,768       6,022            --         12,790
  Depletion, depreciation and amortization......    36,744      28,112            --         64,856
  Impairment of proved properties...............        --       2,911            --          2,911
  Impairment of unproved properties.............        --       5,124            --          5,124
  Stock compensation expense....................     2,156       3,383            --          5,539
  General and administrative....................     3,383       4,159            --          7,542
                                                  --------    --------      --------       --------
     Total operating expenses...................    55,980      90,844            --        146,824
                                                  --------    --------      --------       --------
     Operating income...........................    39,356      36,253            --         75,609
                                                  --------    --------      --------       --------
Other income (expense):
  Interest expense..............................    (2,257)     (7,474)           --         (9,731)
  Interest income...............................       416         814            --          1,230
  Other.........................................        76          76            --            152
                                                  --------    --------      --------       --------
Income before income taxes......................    37,591      29,669            --         67,260
                                                  --------    --------      --------       --------
Provision for income taxes:
  Current.......................................        --        (675)           --           (675)
  Deferred......................................   (13,156)     (9,893)           --        (23,049)
                                                  --------    --------      --------       --------
     Total provision for income taxes...........   (13,156)    (10,568)           --        (23,724)
                                                  --------    --------      --------       --------
Net income......................................  $ 24,435    $ 19,101      $     --       $ 43,536
                                                  ========    ========      ========       ========
</Table>

                                       F-39
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
                      FOR THE YEAR ENDED DECEMBER 31, 2000

<Table>
<Caption>
                                                              SUBSIDIARY
                                             PARENT COMPANY   GUARANTORS   ELIMINATIONS   CONSOLIDATED
                                             --------------   ----------   ------------   ------------
                                                                  (IN THOUSANDS)
<S>                                          <C>              <C>          <C>            <C>
Cash flows from operating activities:
  Net income...............................    $  24,435      $  19,101      $     --      $  43,536
  Adjustments to reconcile net income to
     net cash provided by operating
     activities:
     Depletion, depreciation and
       amortization........................       36,744         28,112            --         64,856
     Exploration dry hole costs............        1,564          4,456            --          6,020
     Impairment of proved properties.......           --          2,911            --          2,911
     Impairment of unproved properties.....           --          5,124            --          5,124
     Stock compensation expense............        2,156             --            --          2,156
     Gain on sale of assets................           --         (3,130)           --         (3,130)
     Deferred income taxes.................       13,156          9,893            --         23,049
     Director retainers settled for
       stock...............................           50             --            --             50
     Changes in asset and liabilities, net
       of effects of acquisitions:
       Increase in accounts receivable.....       (8,527)       (20,151)           --        (28,678)
       Decrease (increase) in prepaid
          expenses.........................       (1,256)           117            --         (1,139)
       Increase in accounts payable........        4,926         13,004            --         17,930
       Decrease in accrued expenses........        7,584          2,038            --          9,622
       Increase in ad valorem taxes
          payable..........................           --          2,183            --          2,183
       Increase in income taxes payable....           --            375            --            375
       Decrease in other liabilities.......           --         (1,436)           --         (1,436)
                                               ---------      ---------      --------      ---------
          Net cash provided by operating
            activities.....................       80,832         62,597            --        143,429
                                               ---------      ---------      --------      ---------
Cash flows from investing activities:
  Additions to property and equipment......      (32,676)       (69,553)           --       (102,229)
  Proceeds from sales of assets............           --          6,259            --          6,259
  Merger with EPGC.........................      (42,403)            --            --        (42,403)
  Other acquisitions.......................           --         (1,454)           --         (1,454)
  Increase in intercompany receivable......      (97,347)            --        97,347             --
  Other....................................           --           (342)           --           (342)
                                               ---------      ---------      --------      ---------
          Net cash used in investing
            activities.....................     (172,426)       (65,090)       97,347       (140,169)
                                               ---------      ---------      --------      ---------
Cash flows from financing activities:
  Proceeds from issuance of common stock...      104,052             --            --        104,052
  Proceeds from issuance of long-term
     debt..................................       50,000             --            --         50,000
  Repayment of long-term debt..............      (50,000)      (106,633)           --       (156,633)
  Increase in intercompany payable.........           --         97,347       (97,347)            --
                                               ---------      ---------      --------      ---------
          Net cash provided by (used in)
            financing activities...........      104,052         (9,286)      (97,347)        (2,581)
                                               ---------      ---------      --------      ---------
Net increase (decrease) in cash and cash
  equivalents..............................       12,458        (11,779)           --            679
Cash and cash equivalents, beginning of
  year.....................................           --         19,475            --         19,475
                                               ---------      ---------      --------      ---------
Cash and cash equivalents, end of year.....    $  12,458      $   7,696      $     --      $  20,154
                                               =========      =========      ========      =========
</Table>

                                       F-40
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

17. 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>
                                                     FOR THE YEAR ENDED DECEMBER 31,
                                                   -----------------------------------
                                                      2002         2001        2000
                                                   ----------   ----------   ---------
                                                             (IN THOUSANDS)
<S>                                                <C>          <C>          <C>
Capitalized costs
  Proved oil and natural gas properties..........  $2,177,656   $1,446,331   $ 591,367
  Unproved oil and natural gas properties........     104,430      105,539      40,653
                                                   ----------   ----------   ---------
       Total oil and natural gas properties......   2,282,086    1,551,870     632,020
  Less: Accumulated depletion, depreciation and
     amortization................................    (481,396)    (280,737)   (155,752)
                                                   ----------   ----------   ---------
       Net capitalized costs.....................  $1,800,690   $1,271,133   $ 476,268
                                                   ==========   ==========   =========
Costs incurred
  Proved property acquisition costs..............  $  657,826   $  706,811   $ 182,944
  Unproved property acquisition costs............      30,051       76,401      31,821
  Exploration costs..............................      35,198       60,704      34,622
  Proved developed costs.........................      56,627       60,361      33,836
  Proved undeveloped costs.......................      46,418       55,202      25,122
                                                   ----------   ----------   ---------
       Total.....................................  $  826,120   $  959,479   $ 308,345
                                                   ==========   ==========   =========
</Table>

  OIL AND 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.

     Estimated quantities of the Company's oil and gas reserves and the net
present value of such reserves as of December 31, 2002 are based upon reserve
reports prepared by Ryder Scott Company, L.P. and the Company's engineering
staff. Ryder Scott reports covered 81% of the total net present value of
estimates of total proved reserves, evaluating 58% and auditing 23%. The
internally generated report covered the remaining 19% of the net present value.
At December 31, 2001, Ryder Scott Company, L.P. audited 87% of the total net
present value of estimates of total proved reserves and the remaining 13% of net
present value of the reserves was unaudited. Estimates of total proved reserves
at December 31, 2000 were prepared by Ryder Scott and Netherland, Sewell and
Associates, Inc. and internal estimates. The Ryder Scott and Netherland Sewell
reports covered approximately 85% of the total net present value of the reserves
and the internally generated report covered the remaining 15% of the net present
value. 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 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.

                                       F-41
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

          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 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.

     The estimated net future development costs to develop the booked proved
undeveloped reserves for 2003, 2004 and 2005 are $78.7 million, $143.5 million
and $71.2 million, respectively.

  QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)

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

<Table>
<Caption>
                                                              OIL (MBLS)   GAS (MMCF)
                                                              ----------   ----------
<S>                                                           <C>          <C>
Proved reserves at December 31, 1999........................    32,750       119,338
  Revisions of previous estimates...........................     1,417        10,662
  Discoveries...............................................     3,135        33,445
  Purchase of minerals in place.............................     3,249       116,783
  Sales of minerals in place................................    (2,167)         (447)
  Production................................................    (3,584)      (34,316)
                                                                ------     ---------
Proved reserves at December 31, 2000........................    34,800       245,465
  Revisions of previous estimates...........................    (4,360)       (6,390)
  Discoveries...............................................     6,057        55,366
  Purchase of minerals in place.............................    37,576       283,783
  Sales of minerals in place................................      (488)       (1,599)
  Production................................................    (4,929)      (58,561)
                                                                ------     ---------
Proved reserves at December 31, 2001........................    68,656       518,064
  Revisions of previous estimates...........................     6,008       (15,754)
  Discoveries...............................................     3,082        39,936
  Purchase of minerals in place.............................    12,085       650,230
  Sales of minerals in place................................    (2,735)       (5,555)
  Production................................................    (7,927)      (82,346)
                                                                ------     ---------
Proved reserves at December 31, 2002........................    79,169     1,104,575
                                                                ======     =========
Proved developed reserves at December 31, 2000..............    28,673       185,354
                                                                ======     =========
Proved developed reserves at December 31, 2001..............    51,068       401,823
                                                                ======     =========
Proved developed reserves at December 31, 2002..............    60,576       676,365
                                                                ======     =========
</Table>

                                       F-42
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<Table>
<Caption>
                                                            DECEMBER 31,
                                              -----------------------------------------
                                                 2002            2001           2000
                                              -----------     ----------     ----------
                                                           (IN THOUSANDS)
<S>                                           <C>             <C>            <C>
Future cash flows...........................  $ 6,627,844     $2,543,696     $2,993,022
Future production costs.....................   (1,928,788)      (841,940)      (546,358)
Future development costs....................     (474,447)      (216,708)      (119,415)
                                              -----------     ----------     ----------
Future net cash flows before tax............    4,224,609      1,485,048      2,327,249
Future income taxes.........................   (1,123,508)      (306,261)      (691,048)
                                              -----------     ----------     ----------
Future net cash flows after tax.............    3,101,101      1,178,787      1,636,201
Annual discount at 10%......................   (1,334,650)      (431,758)      (537,802)
                                              -----------     ----------     ----------
Standardized measure of discounted future
  net cash flows............................  $ 1,766,451     $  747,029     $1,098,399
                                              ===========     ==========     ==========
Discounted future net cash flows before
  income taxes..............................  $ 2,405,818(1)  $  924,343(2)  $1,570,892
                                              ===========     ==========     ==========
</Table>

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

(1) The difference in the discounted future net cash flows before income taxes
    from December 31, 2001 to December 31, 2002 resulted almost entirely from
    (i) the addition of 722.7 Bcfe of proved reserves due to acquisitions, (ii)
    the addition of 58.4 Bcfe as discoveries and extension and (iii) the upward
    revision of 20 Bcfe due to revisions of previous estimates and (iv) the
    change in commodity prices used to determine future cash flows.

(2) The difference in the discounted future net cash flows before income taxes
    from December 31, 2000 to December 31, 2001 resulted almost entirely from
    (i) the addition of 502.7 Bcfe of proved reserves acquired in connection
    with the Merger, (ii) the addition of 92 Bcfe as discoveries and extension
    and (iii) the downward revision of 33 Bcfe due to revisions of previous
    estimates and (iv) the decrease in commodity prices used to determine future
    cash flows.

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

<Table>
<Caption>
                                                    FOR THE YEAR ENDED DECEMBER 31,
                                                  ------------------------------------
                                                     2002         2001         2000
                                                  ----------   -----------   ---------
                                                             (IN THOUSANDS)
<S>                                               <C>          <C>           <C>
Oil and natural gas sales, net of production
  costs.........................................  $ (307,187)  $  (243,399)  $(196,608)
Net changes in anticipated prices and production
  costs.........................................     659,541    (1,179,511)    369,244
Extensions and discoveries, less related
  costs.........................................     125,262       139,078     228,685
Changes in estimated future development costs...     (32,309)      (10,284)    (15,807)
Previously estimated development costs
  incurred......................................      73,422        50,704      16,827
Net change in income taxes......................    (462,053)      295,179    (445,830)
Purchase of minerals in place...................     825,382       489,733     748,854
Sales of minerals in place......................     (12,024)       (8,466)     (3,205)
Accretion of discount...........................      92,434       157,089      34,910
Revision of quantity estimates..................      39,468       (35,347)     48,384
Changes in production rates and other...........      17,486        (6,146)     (9,490)
                                                  ----------   -----------   ---------
  Change in standardized measure................  $1,019,422   $  (351,370)  $ 775,964
                                                  ==========   ===========   =========
</Table>

                                       F-43
<PAGE>
                         WESTPORT RESOURCES CORPORATION

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


<Table>
<Caption>
                                   FIRST      SECOND     THIRD      FOURTH
                                  QUARTER    QUARTER    QUARTER    QUARTER    FULL YEAR
                                  --------   --------   --------   --------   ---------
                                        (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                               <C>        <C>        <C>        <C>        <C>
2002
Total revenues..................  $ 71,948   $111,331   $103,048   $113,241   $399,568
Gross profit(1).................    52,755     80,479     72,709     99,968    305,911
Net income (loss)...............   (19,473)     2,410      2,165    (13,668)   (28,566)
Net income (loss) available to
  common stock..................   (20,663)     1,219        974    (14,858)   (33,328)
Net income (loss) per share(2)
  Basic.........................     (0.40)      0.02       0.02      (0.27)     (0.63)
  Diluted.......................     (0.40)      0.02       0.02      (0.27)     (0.63)
2001
Total revenues..................  $ 97,102   $ 72,862   $ 86,545   $ 92,351   $348,860
Gross profit(1).................    79,542     54,576     50,830     60,542    245,490
Net income (loss)...............    34,032     16,657     11,760    (12,628)    49,821
Net income (loss) available to
  common stock..................    34,032     16,657     11,363    (13,818)    48,234
Net income per share(2)
  Basic.........................      0.89       0.43       0.26      (0.27)      1.11
  Diluted.......................      0.87       0.42       0.25      (0.27)      1.09
</Table>


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

(1) Gross profit is computed as the excess of oil and natural gas revenues,
    including hedge settlements over operating expenses. Operating expenses
    include lease operating expense, production taxes and transportation costs.

(2) The sum of the individual quarterly net income (loss) per share may not
    agree with year-to-date net income per share as each period's computation is
    based on the weighted average number of common shares outstanding during the
    period.

                                       F-44
<PAGE>

                               INDEX TO EXHIBITS


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
    1.1       --    Purchase Agreement, dated as of March 27, 2003, by and among
                    Westport, subsidiary guarantors party thereto and Lehman
                    Brothers Inc. (incorporated by reference to Exhibit 1 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-105834), filed with the SEC on June 4, 2003).
    1.2       --    Stock Purchase Agreement, dated as of November 15, 2002, by
                    and among Westport, Spindrift Partners, L.P., Spindrift
                    Investors (Bermuda) L.P., Global Natural Resources III and
                    Global Natural Resources III L.P. (incorporated by reference
                    to Exhibit 1 to Westport's Registration Statement on Form
                    S-3 (Registration No. 333-102281), filed with the SEC on
                    December 31, 2002).
    2.1       --    Agreement and Plan of Merger, dated as of March 9, 2000, by
                    and among Westport Oil and Gas Company, Inc., Westport
                    Energy Corporation, Equitable Production Company, Equitable
                    Production (Gulf) Company and EPGC Merger Sub Corporation
                    (incorporated by reference to Exhibit 2.1 to the
                    Registration Statement on Form S-1 of Westport Resources
                    Corporation, a Delaware corporation (Registration No.
                    333-40422), filed with the SEC on June 29, 2000).
    2.2       --    Agreement and Plan of Merger, dated as of June 8, 2001,
                    among Belco and Westport Resources Corporation, a Delaware
                    corporation (incorporated by reference to Exhibit 2.1 to
                    Belco's Registration Statement on Form S-4/A (Registration
                    No. 333-64320), filed with the SEC on July 24, 2001).
    2.3       --    Purchase and Sale Agreement, dated November 6, 2002, among
                    Westport and certain affiliates of El Paso Corporation
                    parties thereto (incorporated by reference to Exhibit 2 to
                    Westport's Current Report on Form 8-K/A, filed with the SEC
                    on December 27, 2002).
    3.1       --    Amended Articles of Incorporation of Westport (incorporated
                    by reference to Exhibit 3.1 to Westport's Registration
                    Statement on Form 8-A/A, filed with the SEC on August 31,
                    2001).
    3.2       --    Certificate of Amendment to Amended Articles of
                    Incorporation of Westport, dated March 5, 2003 (incorporated
                    by reference to Exhibit 3.2 to Westport's Quarterly Report
                    on Form 10-Q for the quarter ended March 31, 2003, filed on
                    May 8, 2003).
    3.3       --    Third Amended and Restated Bylaws of Westport effective as
                    of October 1, 2003 (incorporated by reference to Exhibit 3.3
                    to Westport's Quarterly Report on form 10-Q for the quarter
                    ended September 30, 2003, filed with the SEC on November 14,
                    2003).
    4.1       --    Specimen Certificate for shares of Common Stock of Westport
                    (incorporated by reference to Exhibit 4.1 to Westport's
                    Registration Statement on Form 8-A/A, filed with the SEC on
                    August 31, 2001).
    4.2       --    Specimen Certificate for shares of 6 1/2% Convertible
                    Preferred Stock of Westport (incorporated by reference to
                    Exhibit 4 to Westport's Registration Statement on
                    Form 8-A/A, filed with the SEC on August 31, 2001).
  **4.3       --    Third Amended and Restated Shareholders Agreement dated
                    February 14, 2003 among Westport, ERI, Medicor Foundation,
                    WELLC and certain stockholders named therein.
    4.4       --    Termination and Voting Agreement, dated as of October 1,
                    2003, among Westport, ERI, WELLC, Medicor and certain
                    stockholders named therein (incorporated by reference to
                    Exhibit 4.5 to Westport's Quarterly Report on Form 10-Q for
                    the quarter ended September 30, 2003, filed with the SEC on
                    November 14, 2003).
    4.5       --    Registration Rights Agreement, dated as of October 1, 2003,
                    among Westport, ERI, WELLC, Medicor and certain stockholders
                    named therein (incorporated by reference to Exhibit 4.6 to
                    Westport's Quarterly Report on Form 10-Q for the quarter
                    ended September 30, 2003, filed with the SEC on November 14,
                    2003).
    4.6       --    Registration Rights Agreement, dated as of April 3, 2003,
                    among Westport, subsidiary guarantors party thereto and
                    Lehman Brothers Inc. (incorporated by reference to Exhibit
                    4.7 to Westport's Registration Statement on Form S-4
                    (Registration No. 333-105834), filed with the SEC on June 4,
                    2003).
</Table>

<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
    4.7       --    Indenture, dated as of November 5, 2001, among Westport,
                    subsidiary guarantors from time to time party thereto and
                    The Bank of New York, as trustee (incorporated by reference
                    to Exhibit 4.4 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-77060), filed with the SEC on
                    January 18, 2002).
    4.8       --    First Supplemental Indenture, dated as of December 31, 2001,
                    among Westport, existing subsidiary guarantors party
                    thereto, new subsidiary guarantors named therein and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.5 to Westport's Registration Statement on Form S-4
                    (Registration No. 333-77060), filed with the SEC on January
                    18, 2002).
    4.9       --    Second Supplemental Indenture, dated as of December 17,
                    2002, among Westport, existing subsidiary guarantors party
                    thereto, new subsidiary guarantors named therein and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.9 to Westport's Registration Statement on Form S-4
                    (Registration No. 333-102705), filed with the SEC on January
                    24, 2003).
    4.10      --    Third Supplemental Indenture, dated as of April 3, 2003,
                    among Westport, subsidiary guarantors party thereto and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.11 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-105834), filed on June 4, 2003).
    4.11      --    Indenture, dated as of September 23, 1997, among Belco, as
                    issuer, and The Bank of New York, as trustee (incorporated
                    by reference to Exhibit 4.1 of Belco's Registration
                    Statement on Form S-4 (Registration No. 333-37125), filed
                    with the SEC on February 6, 1996).
    4.12      --    Supplemental Indenture dated as of February 25, 1998 between
                    Coda Energy, Inc., Diamond Energy Operating Company, Electra
                    Resources, Inc., Belco Operating Corp., Belco Energy L.P.,
                    Gin Lane Company, Fortune Corp., BOG Wyoming LLC and Belco
                    Finance Co. (individually, the Subsidiary Guarantors), a
                    subsidiary of Belco, and The Bank of New York, a New York
                    banking corporation (as Trustee) amending the Indenture
                    filed as Exhibit 4.2 above (incorporated by reference to
                    Exhibit 4.3 of Belco's Annual Report on Form 10-K for the
                    fiscal year ended December 31, 1997, filed with the SEC on
                    March 26, 1998).
    4.13      --    Second Supplemental Indenture, dated as of August 21, 2001,
                    among Westport, certain subsidiary guarantors party thereto
                    and The Bank of New York, as trustee (incorporated by
                    reference to Exhibit 4.3 to Westport's Quarterly Report on
                    Form 10-Q for the quarter ended September 30, 2001, filed
                    with the SEC on November 14, 2001).
    4.14      --    Third Supplemental Indenture, dated as of December 31, 2001,
                    among Westport, existing subsidiary guarantors party
                    thereto, new subsidiary guarantors named therein and The
                    Bank of New York, as trustee (incorporated by reference to
                    Exhibit 4.10 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-77060), filed with the SEC on
                    January 18, 2002).
    4.15      --    Fourth Supplemental Indenture, dated as of December 17,
                    2002, among Westport, existing subsidiary guarantors, new
                    subsidiary guarantors and The Bank of New York, as trustee
                    (incorporated by reference to Exhibit 4.14 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-102705), filed with the SEC on January 24, 2003).
    4.16      --    Certificate of Designations of 6 1/2% Convertible Preferred
                    Stock dated March 5, 1998 (incorporated by reference to
                    Exhibit 4.1 of Belco's Current Report on Form 8-K, filed on
                    March 11, 1998).
    4.17      --    Form of 8 1/4% Note (contained in the Indenture listed as
                    Exhibit 4.4 above) (incorporated by reference to Exhibit 4.4
                    to Westport's Registration Statement on Form S-4
                    (Registration No. 333-77060), filed with the SEC on January
                    18, 2002).
    4.18      --    Form of 8 7/8% Note (contained in the Indenture listed as
                    Exhibit 4.8 above) (incorporated by reference to Exhibit 4.1
                    to Belco's Registration Statement on Form S-4 (Registration
                    No. 333-37125), filed with the SEC on February 6, 1996).
    4.19      --    Form of Indenture for Senior Debt Securities (incorporated
                    by reference to Exhibit 4.1 to Belco's Amendment No. 1 to
                    the Registration Statement on Form S-3 (Registration No.
                    333-42107), filed with the SEC on December 23, 1997).
</Table>

<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
    4.20      --    Form of Indenture for Subordinated Debt Securities
                    (incorporated by reference to Exhibit 4.2 to Belco's
                    Amendment No. 1 to the Registration Statement on Form S-3
                    (Registration No. 333-42107), filed with the SEC on December
                    23, 1997).
   10.1       --    Credit Agreement, dated as of December 17, 2002, among
                    Westport, certain lenders from time to time party thereto,
                    Credit Suisse First Boston Corporation, as syndication
                    agent, JPMorgan Chase Bank, as administrative agent and
                    issuing bank, certain documentation agents party thereto,
                    Wachovia Bank, N.A., as senior managing agent, and certain
                    managing agents named therein (incorporated by reference to
                    Exhibit 10.1 to Westport's Registration Statement on Form
                    S-4 (Registration No. 333-102705), filed with the SEC on
                    January 24, 2003).
   10.2       --    First Amendment to Credit Agreement, dated as of October 15,
                    2003, among Westport, subsidiary guarantors party thereto,
                    JP Morgan Chase Bank, as administrative agent, and certain
                    lenders named therein (incorporated by reference to Exhibit
                    10.1 to Westport's Quarterly Report on Form 10-Q for the
                    quarter ended September 30, 2003, filed with the SEC on
                    November 14, 2003).
   10.3       --    Subsidiary Guarantee, dated as of December 17, 2002, by each
                    subsidiary guarantor party thereto in favor of JPMorgan
                    Chase Bank, as administrative agent for certain lenders and
                    creditors (incorporated by reference to Exhibit 10.2 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-102705), filed with the SEC on January 24, 2003).
   10.4       --    Westport Resources Corporation 2000 Stock Incentive Plan, as
                    amended on August 21, 2001 (incorporated by reference to
                    Exhibit 4.4 to Westport's Registration Statement on Form
                    S-8, filed with the SEC on August 31, 2001).
   10.5       --    Westport Resources Corporation Annual Incentive Plan 2000
                    (incorporated by reference to Exhibit 10.6 to Old Westport's
                    Registration Statement on Form S-1 (Registration No.
                    333-40422), filed with the SEC on June 29, 2000).
   10.6       --    Employment Agreement, effective as of April 1, 2002, between
                    Westport and Donald D. Wolf (incorporated by reference to
                    Exhibit 10.1 to Westport's Quarterly Report on Form 10-Q for
                    the quarter ended March 31, 2002, filed with the SEC on May
                    13, 2002).
   10.7       --    Employment Agreement, effective as of April 1, 2002, between
                    Westport and Barth E. Whitham (incorporated by reference to
                    Exhibit 10.2 to Westport's Quarterly Report on Form 10-Q for
                    the quarter ended March 31, 2002, filed with the SEC on May
                    13, 2002).
   10.8       --    Form of Indemnification Agreement between Westport and its
                    officers and directors (incorporated by reference to Exhibit
                    10.1 to Westport's Quarterly Report on Form 10-Q for the
                    quarter ended June 30, 2002, filed with the SEC on August
                    14, 2002).
   10.9       --    Belco Oil & Gas Corp. 1996 Nonemployee Directors' Stock
                    Option Plan (incorporated by reference to Exhibit 10.1 of
                    Belco's Registration Statement on Form S-1 (Registration No.
                    333-1034), filed with the SEC on February 6, 1996).
   10.10      --    First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee
                    Directors' Stock Option Plan (incorporated by reference to
                    Exhibit 10.1 of Belco's Quarterly Report on Form 10-Q for
                    the quarter ended June 30, 1999, filed with the SEC on
                    August 13, 1999).
   10.11      --    Belco Oil & Gas Corp. 1996 Stock Incentive Plan
                    (incorporated by reference to Exhibit 10.2 of Belco's
                    Registration Statement on Form S-1 (Registration No.
                    333-1034), filed with the SEC on February 6, 1996).
   10.12      --    First Amendment to Belco Oil & Gas Corp. 1996 Stock
                    Incentive Plan (incorporated by reference to Exhibit 10.2 of
                    Belco's Quarterly Report on Form 10-Q for the quarter ended
                    June 30, 2000, filed with the SEC on August 14, 2000).
   10.13      --    Form of Indemnification Agreement between Belco and its
                    officers and directors (incorporated by reference to Exhibit
                    10.6 of Belco's Registration Statement on Form S-1
                    (Registration No. 333-1034), filed with the SEC on February
                    6, 1996).
   10.14      --    Belco Oil & Gas Corp. Retention and Severance Benefit Plan
                    dated June 8, 2001 (incorporated by reference to Exhibit
                    10.18 to Belco's Registration Statement on Form S-4/A
                    (Registration No. 333-64320), filed with the SEC on July 24,
                    2001).
</Table>

<PAGE>


<Table>
<Caption>
EXHIBIT NO.                             EXHIBIT DESCRIPTION
-----------                             -------------------
<S>           <C>   <C>
   10.15      --    Amended and Restated Well Participation Letter Agreement
                    dated as of December 31, 1992 between Chesapeake Operating,
                    Inc. and Belco, as amended by (i) Letter Agreement dated
                    April 14, 1983, (ii) Amendment dated December 31, 1993, and
                    (iii) Third Amendment dated December 30, 1994 (incorporated
                    by reference to Exhibit 10.7 of Belco's Registration
                    Statement on Form S-1 (Registration No. 333-1034), filed
                    with the SEC on February 6, 1996).
   10.16      --    Sale Agreement (Independence) dated as of June 10, 1994
                    between Chesapeake Operating, Inc. and Belco (incorporated
                    by reference to Exhibit 10.10 of Belco's Registration
                    Statement on Form S-1 (Registration No. 333-1034), filed
                    with the SEC on February 6, 1996).
   10.17      --    Sale and Area of Mutual Interest Agreement (Greater
                    Giddings) dated as of December 30, 1994 between Chesapeake
                    Operating, Inc. and Belco (incorporated by reference to
                    Exhibit 10.12 of Belco's Registration Statement on Form S-1
                    (Registration No. 333-1034), filed with the SEC on February
                    6, 1996).
   10.18      --    Golden Trend Area of Mutual Interest Agreement dated as of
                    December 17, 1992 between Chesapeake Operating, Inc. and
                    Belco (incorporated by reference to Exhibit 10.13 of Belco's
                    Registration Statement on Form S-1 (Registration No.
                    333-1034), filed with the SEC on February 6, 1996).
   10.19      --    Form of Participation Agreement for Belco Oil & Gas Corp.
                    1992 Moxa Arch Drilling Program (incorporated by reference
                    to Exhibit 10.15 of Belco's Registration Statement on Form
                    S-1 (Registration No. 333-1034), filed with the SEC on
                    February 6, 1996).
   10.20      --    Form of Offset Participation Agreement to the Moxa Arch 1992
                    Offset Drilling Program (incorporated by reference to
                    Exhibit 10.16 of Belco's Registration Statement on Form S-1
                    (Registration No. 333-1034), filed with the SEC on February
                    6, 1996).
   10.21      --    Form of Participation Agreement for Belco Oil & Gas Corp.
                    1993 Moxa Arch Drilling Program (incorporated by reference
                    to Exhibit 10.17 of Belco's Registration Statement on Form
                    S-1 (Registration No. 333-1034), filed with the SEC on
                    February 6, 1996).
   10.22      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Grant W. Henderson
                    (incorporated by reference to Exhibit 10.24 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.23      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Lon McCain
                    (incorporated by reference to Exhibit 10.25 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.24      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Kenneth D.
                    Anderson (incorporated by reference to Exhibit 10.26 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-77060), filed with the SEC on January 18, 2002).
   10.25      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Lynn S. Belcher
                    (incorporated by reference to Exhibit 10.27 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.26      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Brian K. Bess
                    (incorporated by reference to Exhibit 10.28 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.27      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Howard L. Boigon
                    (incorporated by reference to Exhibit 10.29 to Westport's
                    Registration Statement on Form S-4 (Registration No.
                    333-77060), filed with the SEC on January 18, 2002).
   10.28      --    Change in Control Severance Protection Agreement, dated as
                    of December 1, 2001, between Westport and Robert R. McBride,
                    Jr. (incorporated by reference to Exhibit 10.30 to
                    Westport's Registration Statement on Form S-4 (Registration
                    No. 333-77060), filed with the SEC on January 18, 2002).
</Table>