WESTPORT RESOURCES CORP /NV/ - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K

(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 .

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

NEVADA 13-3869719
(State of incorporation or organization) (I.R.S. Employer
Identification No.)

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:

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.
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TABLE OF CONTENTS

1

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

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 21.

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, referred
to as the Revolving Credit Facility, with JPMorgan Chase Bank and Credit Suisse
First Boston Corporation 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
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 $429 million.

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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:

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(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

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

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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 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

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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 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

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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, 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

7

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 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

8

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.

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

9

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. 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

10

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.

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.

11

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.

RISK FACTORS

In addition to the other information included in this report, the following
risk factors should be considered in evaluating our business and future
prospects. The risk factors described below are not necessarily exhaustive and
you are encouraged to perform your own investigation with respect to us and our
business. You should also 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 $2.94/Mcf, respectively, with production totaling 129.9 Bcfe and
combined oil and natural gas sales of $429.3 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;

12

- 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.

WE WILL REQUIRE SUBSTANTIAL CAPITAL TO FUND OUR OPERATIONS.

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 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.

13

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 $799.4 million and
stockholders' equity of $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.

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. We cannot be
certain that our earnings will be sufficient 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. Further, failing to comply with the financial and other
restrictive covenants in our debt instruments could result in an event of
default under such instruments, which could adversely affect our business,
financial condition and results of operations.

IN LIGHT OF OUR CURRENT INDEBTEDNESS, 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 substantially more
debt in the future. Although the agreements and indentures governing the terms
of our debt impose restrictions on our incurrence of additional indebtedness,
these restrictions 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.

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

If our cash flow and capital resources are insufficient to fund our debt
obligations, we may be forced to sell assets, seek additional equity or debt
capital or restructure our debt. 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. Our cash flow and capital
resources may be insufficient for payment of interest on and/or principal of our
debt in the future and any such alternative measures may be unsuccessful or may
not permit us to meet scheduled debt service obligations, which could cause us
to default on our obligations and impair our liquidity.

14

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. We believe these issues were conclusively settled as a
result of the Ute Indian Tribe litigation and have no reason to expect that
similar claims will be or could be asserted in the future. We cannot be certain,
however, that additional claims will not be asserted or, if asserted, that such
claims would not be successful. If claims of this nature were successfully
asserted 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.

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.

15

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. While intended to reduce the effects of volatile
oil and natural gas prices and basis differentials, 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 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

16

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.

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

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, there is no assurance that such oil and natural
gas can be economically produced or satisfactorily marketed. There can be no
assurance that new wells we drill will be productive or that we will 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.

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, while our
revenues may increase if oil and natural gas prices increase significantly, 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 set forth in this report 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;

- assumptions regarding future operating costs;

- estimates of future severance and excise taxes;

17

- assumptions regarding capital expenditures; and

- estimates regarding 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 report 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 United States Securities and Exchange
Commission, or SEC, the estimated discounted net cash flows from proved reserves
are generally based on prices and costs as of the date of the estimate, whereas
actual future prices and costs may be materially higher or lower.

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

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;

- 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. Although we believe that we are in substantial compliance
with all applicable laws and regulations, we cannot be certain that existing
laws or regulations, as currently interpreted or reinterpreted in the future, or
future laws or regulations will not harm our business, results of operations and
financial condition. We may be required to make large 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;

18

- 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.

We could also experience significant delays in operations on our
properties, inability to develop particular properties, or significantly
increased costs of operations 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.

WE CANNOT CONTROL ACTIVITIES ON PROPERTIES WE DO NOT OPERATE. INABILITY TO
FUND OUR CAPITAL EXPENDITURES MAY RESULT IN REDUCTION OR FORFEITURE OF OUR
INTERESTS IN SOME OF OUR NON-OPERATED PROJECTS.

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.

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 not willing 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;

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- 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.

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.

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.

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WE DEPEND UPON OUR MANAGEMENT TEAM AND OUR OPERATIONS REQUIRE US TO ATTRACT
AND RETAIN EXPERIENCED TECHNICAL PERSONNEL.

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 members of our management team could have an
adverse effect on our business. 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 DEPENDS UPON FACTORS OVER WHICH WE MAY
HAVE NO CONTROL.

The marketability of our production depends in part upon the availability,
proximity and capacity of pipelines, natural gas gathering systems and
processing facilities. Any significant change in market factors affecting these
infrastructure facilities could adversely impact our ability to deliver the oil
and natural gas we produce to market in an efficient manner, which could harm
our financial condition and results of operations. We deliver oil and natural
gas through gathering systems and pipelines that we do not own. These facilities
may not be available to us in the future. Our ability to produce and market oil
and natural gas is affected and may be also harmed by:

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

- transportation, tax and energy policies;

- changes in supply and demand; and

- general economic conditions.

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

Our principal stockholders, including Medicor Foundation, Westport Energy
LLC, ERI Investments, Inc., an affiliate of Equitable Resources Corp., and the
Belfer Group, a group of former Belco stockholders, together beneficially own
approximately 53% of our outstanding common stock. Accordingly, these
stockholders, acting together through a shareholders agreement, based on their
current share ownership, are 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. 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. Although we believe payments, if any, that we are required to make
under existing litigation would not have a material impact on our financial
condition, our liability relating to the marketing of oil and gas may increase
as new cases are decided and the law in this area continues to develop.

21

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

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

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

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

Finding and Development Costs. Capital costs incurred in the
acquisition, exploration, development and revisions of proved oil and
natural gas reserves divided by proved reserve additions.

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.

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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 oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.

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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.

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
daily production during the fourth

24

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.

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

(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 Netherland, Sewell and

29

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 for
each of the periods indicated:

30

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

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

(2) Production and price history for 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.

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.

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

31

economic value. Productive wells are those that produce commercial quantities of
hydrocarbons, whether or not they produce a reasonable rate of return.

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.

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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:

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

(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.

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

33

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.

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

(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.

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

35

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 GAAP and 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.

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

36

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.

- 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 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.

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 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

37

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.

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. When
making such assessments, we compare the expected undiscounted future net
revenues on a field-by-field basis with the related net capitalized costs at the
end of each year. When the net capitalized costs exceed the undiscounted future
net revenues, the cost of the property is written down to "fair value," which is
determined using discounted future net revenues based on escalated prices.
Impairments for the years ended December 31, 2002, 2001 and 2000 were calculated
based on 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

38

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.

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 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.

39

RESULTS OF OPERATIONS

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

SUMMARY DATA

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 $112.0
million, or 35%, from $317.3 million in 2001 to $429.3 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. The increases in
oil and natural gas revenues were partially offset by oil and natural gas
production declines in the Gulf of Mexico developed properties 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. The increases in production volumes were partially
offset by oil and natural gas production declines in the Gulf of Mexico
developed properties. 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

40

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.

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.

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.

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.

41

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 $3.6
million, or 70%, from $5.2 million in 2001 to $8.8 million in 2002. The increase
from the acquired Belco properties accounted for $2.9 million of the increase.
The remaining increase was primarily due to a one time adjustment related to
certain coalbed methane wells.

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:

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

42

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.

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 $51.5 million and the change in the

43

income taxes from a tax provision to a tax benefit of $48.2 million offset by
increases of $151.4 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 $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.

44

REVOLVING CREDIT FACILITY

On December 17, 2002, we entered into the Revolving Credit Facility with
JPMorgan Chase Bank and Credit Suisse First Boston Corporation 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 and
contains covenants and default provisions customary for similar credit
facilities. We made borrowings under the Revolving Credit Facility to 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 and the ratings of our senior unsecured debt as issued by Standard and
Poor's Rating Group and Moody's Investor Services, Inc.

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.

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.

As of February 28, 2003, we had borrowings of $80.0 million (with an
average interest rate of 3.3%) and letters of credit issued of approximately
$162.3 million outstanding under the Revolving Credit Facility, and available
unused borrowing capacity of approximately $227.7 million. The increase in
letters of credit issued is due to the effect of increased commodity prices on
the margin requirements of our oil and natural gas derivative contracts with our
counterparties. The Revolving Credit Facility currently limits our outstanding
letters of credit to $200 million.

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.

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, 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, we issued
$275 million of our 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. We used the proceeds from the
sale of the old notes to finance, in part, the Acquisition. On January 24, 2003,
we filed the exchange offer

45

registration statement pursuant to a registration rights agreement relating to
the old notes. In the event we fail to comply with some of our obligations under
the registration rights agreement relating to the old notes, we will pay
additional interest on the old notes. The exchange offer registration statement
was declared effective by the SEC on January 30, 2003. We were 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. We intend to
close the exchange offer in March of this year.

The notes are senior subordinated unsecured obligations of Westport and are
fully and unconditionally guaranteed on a senior subordinated basis by some of
our existing and future restricted subsidiaries. The notes mature on November 1,
2011. We pay interest on the notes semiannually on May 1 and November 1. Our
first interest payment on the old notes will be May 1, 2003. We are 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, we are
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 we fail to comply with some of our obligations under the
registration rights agreement relating to the old notes, we will pay additional
interest on the old notes.

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 $230 million. 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 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

46

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, 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 Rocky Mountain Index, or CIGRM, with a

47

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 CIGRM 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 CIGRM 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:

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

(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 CIGRM swap sold transaction, the counterparty is required
to make a payment to Westport in the event that the CIGRM 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 CIGRM
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 CIGRM) 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 CIGRM) for any settlement period is
less than the swap differential price for such hedge.

49

INTEREST RATE SWAP AGREEMENTS

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

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.

As of December 31, 2002, we recorded a derivative asset of $7.9 million
related to the interest rate swap designated as a fair value hedges, with a
corresponding debt increase.

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 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.

50

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

The information called for by Item 10 of this report is incorporated by
reference from our definitive Proxy Statement to be filed with the SEC pursuant
to Regulation 14A under the Exchange Act.

ITEM 11. EXECUTIVE COMPENSATION

The information called for by Item 11 of this report is incorporated by
reference from our definitive Proxy Statement to be filed with the SEC pursuant
to Regulation 14A under the Exchange Act.

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 our definitive Proxy Statement to be filed with the SEC pursuant
to Regulation 14A under the Exchange Act.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information called for by Item 13 of this report is incorporated by
reference from our definitive Proxy Statement to be filed with the SEC pursuant
to Regulation 14A under the Exchange Act.

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.

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.

51

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

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

* Filed herewith.

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.

55

(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.

56

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: March 7, 2003

WESTPORT RESOURCES CORPORATION

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

POWER OF ATTORNEY

The undersigned directors and officers of Westport Resources Corporation
hereby constitute and appoint Donald D. Wolf, Barth E. Whitham and Lon McCain,
and each of them, with the power to act without the other and with full power of
substitution and resubstitution, our true and lawful attorneys-in-fact and
agents with full power to execute in our name and behalf in the capacities
indicated below any and all amendments to this report and to file the same, with
all exhibits and other documents relating thereto and hereby ratify and confirm
all that such attorneys-in-fact, or either of them, or their substitutes, may
lawfully do or cause to be done by virtue hereof. 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 March 7, 2003:

58

CERTIFICATION

I, Donald D. Wolf, Chairman of the Board and Chief Executive Officer of Westport
Resources Corporation, certify that:

1. I have reviewed this annual report on Form 10-K of Westport Resources
Corporation;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

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

Date: March 7, 2003

59

CERTIFICATION

I, Lon McCain, Vice President, Chief Financial Officer and Treasurer of Westport
Resources Corporation, certify that:

1. I have reviewed this annual report on Form 10-K of Westport Resources
Corporation;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

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

Date: March 7, 2003

60

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Reports of Independent Public Accountants................... F-2
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

F-1

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

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

WESTPORT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial
statements.
F-4

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these consolidated financial
statements.
F-5

WESTPORT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

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

F-6

WESTPORT RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these consolidated financial
statements.
F-7

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 less cost to sell, whether reported in
continuing operations or in discontinued operations. In applying this

F-8

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

statement, the Company compares the expected undiscounted future net revenues on
a field-by-field basis with the related net capitalized costs at the end of each
period. When the net capitalized costs exceed the undiscounted future net
revenues, the cost of the property is written down to "fair value," which is
determined using the discounted future net revenues on a field-by-field basis.
In 2002, 2001 and 2000, the Company recorded proved property impairments of
$19.7 million, $9.4 million and $2.9 million, respectively. 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. Sales proceeds from unproved oil and natural gas properties are
credited to related costs of the prospect sold until all such costs are
recovered and then to net gain or loss on sales of unproved oil and natural gas
properties.

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.

F-9

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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
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.

F-10

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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. We recorded goodwill in connection with the Merger for our 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. We adopted SFAS No. 142 effective January 1,
2002.

In accordance with SFAS No. 142, we were required to perform an initial
impairment review of our goodwill as of January 1, 2002 and will perform an
annual impairment review hereafter. We 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 our reporting units had not been impaired as of June 30,
2002. We performed our annual impairment review as of December 31, 2002 and
based on this goodwill in each of our reporting units had not been impaired.

During the second quarter ended June 30, 2002, the Company completed the
final evaluation of the purchase price allocation in connection with the Merger.
Reclassifications were made from unproved and proved oil and natural gas
properties totaling $19.7 and $10.3 million, respectively, to goodwill. In
addition, goodwill was increased by $1.9 million as a result of additional
merger costs and other miscellaneous adjustments.

The total adjustment to unproved properties was comprised of two
components. The first component resulted from the determination that, as of the
date of the Merger, certain acreage positions had expired. The second component
resulted from a difference in the way acreage was allocated to proved
properties. Prior to the Merger, Belco allocated only net well acreage to a
specific spacing tract, while Westport had a policy of allocating acreage to
proved properties based on an assumption that a producing well holds all the
acreage on a lease. The application of Westport's policy to Belco properties
resulted in a reduced acreage position.

The adjustment to proved properties was made as a result of the final
evaluation by an outside consulting firm of the fair value of certain non-core
properties in the lower 15% of the value of Belco properties acquired

F-11

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in the Merger. The final evaluation determined that the value of these
properties included unsupportable estimates of certain undeveloped reserves. 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.

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.

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

F-12

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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):

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
========

F-13

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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):

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
========

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.

F-14

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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
==========

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

F-15

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 Rocky Mountain Index ("CIGRM") 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 CIGRM 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.

F-16

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

(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.

F-17

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(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 CIGRM) 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 CIGRM) 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.

F-18

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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 owners of the
Company. The components of other comprehensive income net of tax for the twelve
months ended December 31, 2002 and 2001 are as follows (in thousands):

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.

F-19

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. INCOME TAXES

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

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

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

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

F-20

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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:

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

(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 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

F-21

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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.
F-22

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 (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.

F-23

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

YEAR ENDING DECEMBER 31,
2003........................................................ $ --
2004........................................................ --
2005........................................................ --
2006........................................................ 80,000
2007........................................................ 127,587
Thereafter.................................................. 591,771
--------
$799,358
========

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 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.

F-24

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. 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.

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.

F-25

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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:

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

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

F-26

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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:

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 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:

F-27

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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):

YEAR ENDING DECEMBER 31
2003........................................................ $1,196
2004........................................................ 885
2005........................................................ 1,177
2006........................................................ 1,256
2007........................................................ 1,160
Thereafter.................................................. 522
------
$6,196
======

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.

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

F-28

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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.

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

F-29

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

based on the profit or loss from operations before income taxes. Corporate
general and administrative expenses are unallocated in 2001 and 2000.
Consolidated and segment financial information is as follows:

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

(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-30

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2002

F-31

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-32

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-33

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2001

F-34

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-35

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-36

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-37

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-38

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:

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.

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.

F-39

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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:

F-40

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)

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

(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)

F-41

WESTPORT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

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

(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-42

INDEX TO EXHIBITS