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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

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

                                   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, 2000

                                       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: 001-16093

                         WESTPORT RESOURCES CORPORATION
             (Exact name of Registrant as specified in its charter)

              Delaware                                 23-3020832
     (State of incorporation or                     (I.R.S. Employer
            organization)                          Identification No.)

                       410 Seventeenth Street, Suite 2300
                             Denver, Colorado 80202
                    (Address of principal executive offices)
                                   (Zip code)

                                 (303) 573-5404
              (Registrant's telephone number including area code):

          Securities registered pursuant to Section 12(b) of the Act:

         Title of Securities                  Exchanges on which Registered
            Common Stock                         New York Stock Exchange
      par value $.01 per share

          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. [X]

   As of March 1, 2001, 38,419,041 shares of the registrant's common stock, par
value $0.01 per share, were outstanding.

   As of March 1, 2001, the aggregate market value of the outstanding shares of
common stock held by non-affiliates was approximately $213,769,878.

                      DOCUMENTS INCORPORATED BY REFERENCE

   Parts of the definitive proxy statement for the registrant's 2001 annual
meeting of stockholders are incorporated by reference into Part III of this
Form 10-K.

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<PAGE>

                               Table of Contents

<TABLE>
<CAPTION>
                                                                           Page
                                                                           ----
 <C>      <S>                                                              <C>
 Special Note Regarding Forward-Looking Statements.......................    1

<CAPTION>
 Item No.
 --------
 <C>      <S>                                                              <C>
 PART I
 Item 1.  Business......................................................     2
 Item 2.  Properties....................................................    18
 Item 3.  Legal Proceedings.............................................    26
 Item 4.  Submission of Matters to a Vote of Security Holders...........    26

 PART II
          Market for Registrant's Common Equity and Related Stockholder
 Item 5.  Matters.......................................................    27
 Item 6.  Selected Financial Data.......................................    29
 Item 7.  Management's Discussion and Analysis of Financial Condition
          and Results of Operations.....................................    30
 Item 7A. Quantitative and Qualitative Disclosures about Market Risk....    37
 Item 8.  Financial Statements and Supplementary Data...................    38
 Item 9.  Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure......................................    38

 PART III
 Item 10. Directors and Executive Officers of the Registrant............    38
 Item 11. Executive Compensation........................................    38
          Security Ownership of Certain Beneficial Owners and
 Item 12. Management....................................................    38
 Item 13. Certain Relationships and Related Transactions................    39

 PART IV
          Exhibits, Financial Statement Schedules, and Reports on Form
 Item 14. 8-K...........................................................    40

 Signatures..............................................................   42
</TABLE>
<PAGE>

               SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

  .  amount, nature and timing of capital expenditures;

  .  drilling of wells;

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

  .  operating costs and other expenses;

  .  cash flow and anticipated liquidity;

  .  prospect exploitation and property acquisitions; and

  .  marketing of oil and natural gas.

   Any or all of our forward-looking statements in this report, including
information incorporated by reference, 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" in "Item 1. Business" will be
important in determining future results. Actual future results may vary
materially. Factors that could cause our results to differ materially from the
results discussed in the forward-looking statements include the risks described
under "Risk Factors," including:

  .  the risks associated with exploration;

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

  .  oil and natural gas price volatility;

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

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

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

  .  potential mechanical failure or underperformance of significant wells;

  .  climatic conditions;

  .  availability and cost of material and equipment;

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

  .  our ability to find and retain skilled personnel;

  .  availability of capital;

  .  the strength and financial resources of our competitors;

  .  regulatory developments;

  .  environmental risks; and

  .  general economic conditions.

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

                                       1
<PAGE>

                                     PART I

ITEM 1. BUSINESS

About Westport

   Westport Resources Corporation, or Westport, is an independent energy
company engaged in oil and natural gas exploitation, acquisition and
exploration activities primarily in the United States. References in this
report to "Westport," "we," "our" or "us" refer to Westport Resources
Corporation. Westport was formed in connection with the merger of Westport Oil
and Gas Company, Inc. with Equitable Production (Gulf) Company, an indirect,
wholly-owned subsidiary of Equitable Resources, Inc. that held certain Gulf of
Mexico assets. 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 16.

   We conduct operations in the Gulf of Mexico, the Rocky Mountains, West
Texas/Mid-Continent and the Gulf Coast. We focus on maintaining a balanced
portfolio of lower-risk, long-life onshore reserves and higher-margin offshore
reserves to provide a diversified cash flow foundation for our exploitation,
acquisition and exploration activities. Onshore, we have built a strong asset
base and achieved steady growth through both property acquisitions and
exploitation activities. We expect to further develop these properties through
lower-risk recovery methods. In the Gulf of Mexico, we own interests in 67
developed blocks and 67 undeveloped blocks, within which we have realized
several recent discoveries and have assembled a large number of future drilling
opportunities. We have budgeted $170 million capital expenditures for 2001 to
pursue our exploitation and exploration opportunities. We believe that our
exploitation and acquisition expertise and our sizable exploration inventory,
together with our operating experience and efficient cost structure, provide us
with substantial growth potential.

   As of December 31, 2000, we had proved reserves of 454 billion cubic feet
equivalent of natural gas, or Bcfe, with a net present value, which is the pre-
tax future net revenues discounted at 10%, of $1,571 million based on NYMEX
prices of $26.83 per barrel of oil and $9.52 per million British thermal units,
or Mmbtu, of natural gas. These reserves, of which 54% were natural gas and 79%
were classified as proved developed, had a reserve life index of 8.1 years. We
operate over 70% of the net present value of our reserves, allowing us to
better manage expenses, capital allocation and the decision-making processes
related to other aspects of exploitation and exploration activities. We
produced 55.8 Bcfe in 2000. The following table sets forth the volume and net
present value of our proved reserves as of December 31, 2000 and a summary of
our 2000 production by area:


<TABLE>
<CAPTION>
                               As of December 31, 2000      Fiscal Year 2000
                            ----------------------------- ---------------------
                             Proved  Net Present % of Net  Average
                            Reserves  Value (in  Present  Production    % of
Area                         (Bcfe)   millions)   Value   (Mmcfe/d)  Production
----                        -------- ----------- -------- ---------- ----------
<S>                         <C>      <C>         <C>      <C>        <C>
Gulf of Mexico.............  166.7    $  910.4     58.0%     69.5       45.5%
Rocky Mountains............  190.7       372.6     23.7      58.3       38.2
West Texas/Mid-Continent...   57.9       115.9      7.4      12.4        8.2
Gulf Coast.................   39.0       172.0     10.9      12.3        8.1
                             -----    --------    -----     -----      -----
Total......................  454.3    $1,570.9    100.0%    152.5      100.0%
                             =====    ========    =====     =====      =====
</TABLE>

Our Strategy

   Our strategy is to continue to grow our reserve base, diversify our risk
profile and expand our investment opportunities by executing on lower-risk
exploitation projects and acquisitions (65% to 75%

                                       2
<PAGE>

of our capital budget), as well as drilling higher-impact exploration prospects
(25% to 35% of our capital budget), thereby balancing risk while maintaining
significant potential for growth. To accomplish this we will:

  .  enhance our existing and acquired properties through exploitation to
     increase production and enlarge our reserve base;

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

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

   We intend to implement our strategy as follows:

   Continue an Active Exploitation Program. In 2000, we drilled 153 development
wells onshore and 24 development wells in the Gulf of Mexico, of which 169 were
successful. Additionally, we expanded two secondary recovery projects. We have
identified significant prospective exploitation projects both onshore and
offshore.

   In 2001, we will continue onshore exploitation programs in the Powder River
Basin coalbed methane play with 85 to 100 wells, Southwestern Wyoming with five
to 10 natural gas wells, the Howard Glasscock field (Permian Basin) with 25 to
30 injectors and oil producers, the Northern Louisiana complex with 45 to 50
wells and the Wiley Field and South Fryburg Tyler area with 15 to 20 horizontal
wells. Offshore we will install production facilities on discoveries on five
blocks and continue to drill a three- to seven-well development program on the
West Cameron 180/198 complex.

   Pursue and Capitalize on Acquisitions. Through a series of acquisitions from
1995 to 1999, Westport substantially increased its reserve base by investing
approximately $250 million in acquiring oil and natural gas properties at an
average cost of $0.90 per Mcfe. It invested an additional $72 million to
exploit these acquired properties and added reserves at an average cost of
$0.52 per Mcfe, thereby reducing average acquisition costs by over 14% to $0.77
per Mcfe. This has resulted in reserve additions that have fully replaced our
production from the acquired properties, while generating cash flows to date
sufficient to recoup more than 71% of total exploitation and acquisition
capital invested.

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

   Capitalize on Extensive Exploration Opportunities. In 2000, we participated
in two exploration wells onshore and 18 exploration wells in the Gulf of
Mexico, of which 12 were successful. As of December 31, 2000, we had a 67-block
exploration inventory in the Gulf of Mexico, in addition to 67 developed
blocks, several of which contain additional exploration opportunities. We have
under license 3-D seismic data covering over 10,000 square miles (1,460 blocks)
and 2-D seismic data covering over 150,000 linear miles in this area. Our
strategy includes acquiring large working interests in internally generated
prospects in order to control activity, and then, prior to drilling, trading a
portion of our positions for prospects developed by others. This allows us to
achieve multiple prospect exposure while diversifying investment risk.

   Onshore, we hold interests in approximately 131,000 gross (approximately
56,000 net) undeveloped acres. Our onshore exploration effort is designed to
enhance reserve and production growth in our core areas by emphasizing and
applying the latest geological, geophysical and drilling

                                       3
<PAGE>

technologies. We seek exploration plays with geological and geophysical
characteristics similar to producing properties in our core areas in order to
leverage our technical and operational expertise. Recent onshore exploration
activities have included horizontal drilling in North Dakota and coalbed
methane drilling in the Powder River Basin of Wyoming.

Initial Public Offering

   On October 19, 2000, we commenced our initial public offering, which
consisted of 9,150,000 shares of our common stock, par value $0.01 per share
(including 2,650,000 shares offered by the selling stockholders), at $15.00 per
share pursuant to the registration statement (No. 333-40422) declared effective
by the SEC on October 19, 2000. Aggregate proceeds from the offering were
$137,250,000 (including $39,750,000 payable to the selling stockholders). On
November 22, 2000, the underwriters exercised their over-allotment option,
which consisted of 1,035,000 shares of our common stock at $15.00 per share.
Aggregate proceeds from the sale of shares pursuant to the over-allotment
option were $15,525,000. In connection with the offering, we incurred total
expenses of approximately $9.1 million, including underwriting discounts and
commissions of approximately $7.6 million and approximately $1.5 million in
other expenses. After deducting expenses of the offering, we received net
offering proceeds of $103.9 million. We used the net offering proceeds to repay
a portion of the debt under our credit agreement.

Purchasers and Marketing

   Our oil and natural gas production is principally sold to end users,
marketers and other purchasers having access to nearby pipeline facilities. In
areas where there is no practical access to pipelines, oil is trucked to
storage facilities. Our marketing of oil and natural gas can be affected by
factors beyond our control, the effects of which cannot be accurately
predicted. For 2000, our largest purchasers included Dynegy Inc., Conoco, Inc.,
and EOTT Energy Corporation, which accounted for 23%, 14%, and 13% of oil and
natural gas sales, respectively. We do not believe, however, that the loss of
any of our purchasers would have a material adverse effect on our operations.

Competition

   We compete with major and independent oil and natural gas companies. Because
oil and natural gas are commodity products that are sold by hundreds of
competitors, we cannot identify with certainty which of our competitors are
material competitors. Some of our competitors have substantially greater
financial and other resources than we do. In addition, larger competitors may
be able to absorb the burden of any changes in Federal, state and local laws
and regulations more easily than we can, which would adversely affect our
competitive position. Our competitors may be able to pay more for exploratory
prospects and productive oil and natural gas properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and
prospects than we can. Further, these companies may enjoy technological
advantages and may be able to implement new technologies more rapidly than we
can. Our ability to explore for oil and natural gas prospects and to acquire
additional properties in the future will depend upon our ability to conduct
operations, to evaluate and select suitable properties, implement advanced
technologies and to consummate transactions in this highly competitive
environment.

Regulation

   Federal Regulation of Sales and Transportation of Natural Gas. Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and the regulations promulgated thereunder by the Federal
Energy Regulatory Commission. In the past, the Federal government has

                                       4
<PAGE>

regulated the prices at which natural gas could be sold. Deregulation of
natural gas sales by producers began with the enactment of the Natural Gas
Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act,
which removed all remaining Natural Gas Act and Natural Gas Policy Act price
and non-price controls affecting producer sales of natural gas effective
January 1, 1993. Congress could, however, reenact price controls in the future.

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

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

   Commencing in May 1994, the Federal Energy Regulatory Commission issued a
series of orders that, among other matters, slightly narrowed its statutory
tests for establishing gathering status and reaffirmed that, except in
situations in which the gatherer acts in concert with an interstate pipeline
affiliate to frustrate the Federal Energy Regulatory Commission's
transportation policies, it does not have pervasive jurisdiction over natural
gas gathering facilities and services, and that such facilities and services
located in state jurisdictions are most properly regulated by state
authorities. This Federal Energy Regulatory Commission action may further
encourage regulatory scrutiny of natural gas gathering by state agencies. We do
not believe that we will be affected by the Federal Energy Regulatory
Commission's new gathering policy any differently than other natural gas
producers, gatherers and marketers.

   Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
and the courts. The natural gas industry historically has been very heavily
regulated; therefore, we can offer you no assurance that the less stringent
regulatory approach recently pursued by the Federal Energy Regulatory
Commission and Congress will continue.

                                       5
<PAGE>

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

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

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

   Environmental Regulations. Our operations, which include the storage of oil
and other hazardous materials, are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection, including those listed below. We could incur
substantial costs, including cleanup costs, fines and civil or criminal
sanctions, as a result of violations of or liabilities under environmental laws
or the non-compliance with environmental permits required at our facilities.
Public interest in the protection of the environment has increased dramatically
in recent years. Offshore drilling in some areas has been opposed by
environmental groups and, in some areas, has been restricted. To the extent
laws are enacted or other governmental action is taken that prohibits or
restricts drilling or otherwise imposes environmental protection requirements
that result in increased costs to the oil and natural gas industry, our
business and prospects could be adversely affected.

   Under the Comprehensive Environmental Response, Compensation, and Liability
Act, also known as the "Superfund" law, as well as similar state statutes, an
owner or operator of real property or a

                                       6
<PAGE>

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

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

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

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

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

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

Operating Hazards and Insurance

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


                                       7
<PAGE>

   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.

Employees

   At December 31, 2000, we had 97 full-time employees and seven consultants.
We believe that our relationships with our employees are satisfactory. None of
our employees is covered by a collective bargaining agreement. From time to
time, we use the services of independent consultants and contractors to perform
various professional services, particularly in the areas of construction,
design, well-site surveillance, permitting and environmental assessment.
Independent contractors often perform field and on-site production operation
services for us, including pumping, maintenance, dispatching, inspection and
testing.

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.

 Oil and natural gas prices fluctuate widely, and low prices could harm our
business.

   Our revenues, operating results and future rate of growth are substantially
dependent upon the prevailing prices of, and demand for, oil and natural gas.
Declines in the prices of, or demand for, oil and natural gas may adversely
affect our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations. Lower oil and natural gas prices may
also reduce the amount of oil and natural gas that we can produce economically.
Historically, the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. We have had considerable
losses in previous years as a result, in part, of this commodity price
volatility. Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control, including:

  .  worldwide and domestic supplies of oil and natural gas;

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

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

  .  the price and level of foreign imports;

  .  the level of consumer demand;

  .  the price and availability of alternative fuels;

  .  the availability of pipeline capacity;

  .  weather conditions;

  .  domestic and foreign governmental regulations and taxes; and

  .  the overall economic environment.


                                       8
<PAGE>

 We are vulnerable to risks associated with operating in the Gulf of Mexico
because a substantial portion of our exploration and production activities is
conducted in that area.

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

  .  adverse weather conditions;

  .  oil field service costs and availability;

  .  compliance with environmental and other laws and regulations; and

  .  failure of equipment or facilities.

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

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

 Exploration is a high-risk activity. The seismic data and other advanced
technologies we use are expensive and cannot eliminate exploration risk.

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

  .  unexpected drilling conditions;

  .  title problems;

  .  pressure or irregularities in formations;

  .  equipment failures or accidents;

  .  adverse weather conditions;

  .  compliance with environmental and other governmental requirements; and

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

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


                                       9
<PAGE>

 The failure to replace our reserves would adversely affect our operations and
financial condition.

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

 Reserve estimates are inherently uncertain. Any material inaccuracies in our
reserve estimates or underlying assumptions, such as the discount rate used,
could cause the quantities and net present value of our reserves to be
overstated.

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


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

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

  .  future operating costs;

  .  severance and excise taxes;

  .  capital expenditures; and

  .  workover and remedial costs.

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

   We operate in the highly competitive areas of oil and natural gas
exploitation, exploration and acquisition. The oil and natural gas industry is
characterized by rapid and significant technological advancements and
introductions of new products and services using new technologies. We face

                                       10
<PAGE>

intense competition from independent, technology-driven companies as well as
from both major and other independent oil and natural gas companies in each of
the following areas:

  .  seeking to acquire desirable producing properties or new leases for
     future exploration;
  .  marketing our oil and natural gas production;
  .  integrating new technologies; and
  .  seeking to acquire the equipment and expertise necessary to develop and
     operate our properties.

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

 We are subject to complex laws and regulations, including environmental
regulations, that can adversely affect the cost, manner or feasibility of doing
business.

   Exploration for and exploitation, production and sale of oil and natural gas
in the United States, and especially in the Gulf of Mexico, are subject to
extensive Federal, state and local laws and regulations, including complex tax
laws and environmental laws and regulations. Failure to comply with these laws
and regulations may result in the suspension or termination of our operations
and subject us to administrative, civil and criminal penalties. Further, these
laws and regulations could change in ways that substantially increase our
costs. We cannot be certain that existing laws or regulations, as currently
interpreted or reinterpreted in the future, or future laws or regulations will
not harm our business, results of operations and financial condition. We may be
required to make large expenditures to comply with environmental and other
governmental regulations. Matters subject to regulation include:

  .  discharge permits for drilling operations;

  .  drilling bonds;

  .  spacing of wells;

  .  unitization and pooling of properties;

  .  environmental protection;

  .  reports concerning operations; and

  .  taxation.

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

  .  personal injuries;

  .  property damage;

  .  oil spills;

  .  discharge of hazardous materials;

  .  well reclamation costs;

  .  remediation and clean-up costs; and

  .  other environmental damages.


                                       11
<PAGE>

 We cannot control the activities on properties we do not operate.

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

  .  timing and amount of capital expenditures;

  .  the operator's expertise and financial resources;

  .  approval of other participants in drilling wells; and

  .  selection of technology.

 Our business involves many operating risks which may result in substantial
losses. Insurance may be unavailable or inadequate to protect us against these
risks.

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

  .  fires;

  .  natural disasters;

  .  explosions;

  .  formations with abnormal pressures;

  .  casing collapses;

  .  embedded oilfield drilling and service tools;

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

  .  blowouts;

  .  surface cratering;

  .  pipeline ruptures or cement failures; and

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

   Any of these risks can cause substantial losses resulting from:

  .  injury or loss of life;

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

  .  pollution and other environmental damage;

  .  regulatory investigations and penalties;

  .  suspension of our operations; and

  .  repair and remediation costs.

   In addition, our offshore operations in the Gulf of Mexico are subject to a
variety of operating risks peculiar to the marine environment, such as
capsizing, collisions and damage or loss from hurricanes or other adverse
weather conditions. These conditions can cause substantial damage to our
facilities and could interrupt production. For example, some of our offshore
facilities in the Gulf of Mexico were damaged by a hurricane in 1998. If we
experience any of these problems, our business and operations may be harmed and
our ability to acquire, explore and develop properties may be reduced or
eliminated.

                                       12
<PAGE>

   As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. However, losses could occur for
uninsurable or uninsured risks, or in amounts in excess of existing insurance
coverage. The occurrence of an event that is not fully covered by insurance
could harm our financial condition and results of operations.

 Our exploitation, acquisition and exploration operations require substantial
capital, and we may be unable to obtain needed financing on satisfactory terms.

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

 The acquisition of oil and natural gas properties imposes substantial risks.

   We constantly evaluate acquisition opportunities and frequently engage in
bidding and negotiation for acquisitions, many of which are substantial. We may
not be successful in identifying or acquiring any material property interests,
which could prevent us from replacing our reserves and adversely affect our
operations and financial condition. If successful in this process, we may be
required to alter or increase substantially our capitalization to finance these
acquisitions through the use of cash on hand, issuance of additional debt or
equity securities, the sale of production payments, borrowing of additional
funds or otherwise. Our existing credit agreement includes covenants limiting
our ability to incur additional indebtedness. If we were to proceed with one or
more acquisitions for stock, our stockholders would suffer dilution of their
interests. These additional capitalization requirements may significantly
affect our risk profile. The acquisition of properties that are substantially
different in operating or geologic characteristics or geographic locations from
our existing properties could change the nature of our operations and business.
While we intend to concentrate on acquiring producing properties with
exploitation and exploration potential located in our current areas of
operation, we may decide to acquire properties located in other geographic
regions.

 Hedging our production may result in losses.

   To reduce our exposure to fluctuations in the prices of oil and natural gas,
we currently and may in the future enter into derivative contracts. We have
incurred losses as a result of derivative contracts in the past. Derivative
contracts expose us to risk of financial loss in some circumstances, including
the following:

  .  production is less than expected;

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

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

In addition, these derivative contracts may limit the benefit we would receive
from increases in the prices for oil and natural gas. If we choose not to
engage in derivative contracts in the future, we may be more adversely affected
by changes in oil and natural gas prices than our competitors who engage in
derivative contracts.

                                       13
<PAGE>

 Our operations require us to attract and retain experienced technical
personnel.

   Our exploratory drilling success depends, in part, on our ability to attract
and retain experienced explorationists and other professional personnel. We
currently employ 25 explorationists and engineers and four geology/geophysical
consultants, all of whom have experience in the geographic areas to which we
have assigned them. Competition for experienced explorationists and engineers
is extremely intense. If we cannot retain these personnel or attract additional
experienced personnel, our ability to compete in the geographic regions in
which we conduct our operations could be harmed.

 The loss of our chief executive officer or other key personnel could adversely
affect us.

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

 The marketability of our production is dependent upon factors over which we
have no control.

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

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

     .  transportation, tax and energy policies;

     .  changes in supply and demand; and

     .  general economic conditions.

 Our principal stockholders own a significant amount of common stock, giving
them a controlling influence over corporate transactions and other matters.

   Westport Energy LLC (formerly Westport Energy Corporation) and ERI
Investments, Inc. (an affiliate of Equitable Production Company), our principal
stockholders, beneficially own a significant amount of our outstanding common
stock. Accordingly, these stockholders, acting together, will be able to
control the outcome of stockholder votes, including votes concerning the
election of directors, the adoption or amendment of provisions in our
certificate of incorporation or bylaws and the approval of mergers and other
significant corporate transactions. This concentrated ownership makes it
unlikely that any other holder or group of holders of common stock will be able
to affect the way we are managed or the direction of our business. These
factors may also delay or prevent a change in the management or voting control
of Westport.

   In addition, we entered into an agreement with our principal stockholders in
connection with the merger on April 7, 2000, between Westport Oil and Gas
Company, Inc. ("Westport Oil and Gas") and Equitable Production (Gulf) Company,
an indirect, wholly-owned subsidiary of Equitable Resources, Inc. ("EPGC"),
that allows these stockholders to maintain their position of control by, among
other things, addressing how these stockholders will vote their shares in the
election of directors.

                                       14
<PAGE>

 Our stock price may fluctuate significantly.

   The trading price of our common stock, and the price at which we may sell
securities in the future, could be subject to significant fluctuations in
response to government regulations, variations in quarterly operating results,
the prices of oil and natural gas and other factors. For example, changes in
regulations applicable to the Gulf of Mexico could adversely affect our
business and operations, and, thus, result in significant fluctuations in the
trading price of our common stock.

 We have not paid dividends and do not anticipate paying any dividends on our
common stock in the foreseeable future.

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

 Our certificate of incorporation contains provisions that could discourage an
acquisition or change of control of Westport.

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

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

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

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

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

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

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

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

 Future sales of our common stock may depress our stock price.

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

                                       15
<PAGE>

   As of March 1, 2001, we had 38.4 million shares of common stock outstanding.
Some of our current stockholders are subject to agreements that limit their
ability to sell their common stock. These holders cannot sell or otherwise
dispose of any shares of common stock until April 17, 2001 without the prior
written approval of Credit Suisse First Boston Corporation, which could, in its
sole discretion, elect to permit resale of shares by existing stockholders
prior to such date.

   In addition, some of our current stockholders have "demand" and/or
"piggyback" registration rights in connection with future offerings of our
common stock. "Demand" rights enable the holders to demand that their shares be
registered and may require us to file a registration statement under the
Securities Act at our expense. "Piggyback" rights provide for notice to the
relevant holders of our stock if we propose to register any of our securities
under the Securities Act of 1933, as amended (the "Securities Act"), and grant
such holders the right to include their shares in the registration statement.
All holders with registration rights have agreed not to exercise their rights
until April 17, 2001 without the consent of Credit Suisse First Boston
Corporation.

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:

   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.

   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.

   Gross Acres. The total acres in which we have a working interest.

   Gross Producing Wells. The total number of producing wells in which we own
any amount of working interest.

                                       16
<PAGE>

   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.

   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.

   Mmcf. One million cubic feet of natural gas, measured at standard
atmospheric conditions.

   Mmcf/d. One million cubic feet of natural gas per day.

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

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

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

   Net Present Value. The present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance with
SEC guidelines, net of estimated lease operating expense, production taxes and
future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, or Federal income taxes and
discounted using an annual discount rate of 10%.

   Net 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.

   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.

                                      17
<PAGE>

   Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

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

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

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

   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.

   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 located in the Gulf of Mexico, the Rocky Mountains, West
Texas/Mid-Continent and the Gulf Coast. We operate over 70% of the net present
value of our reserves. We finance our exploitation, exploration and acquisition
activities through cash flows from operations and

                                       18
<PAGE>

through borrowings under our credit agreement. Set forth below is summary
information concerning average daily production during 2000 and wells, reserves
and net present value as of December 31, 2000 in our major areas of operations.

<TABLE>
<CAPTION>
                         Fiscal Year 2000                         As of December 31, 2000
                         Average Net Daily    ------------------------------------------------------------------
                            Production                      Proved Reserve Quantities       Net Present Value
                         -----------------       Net    ---------------------------------  ---------------------
                                              Producing  Crude  Natural Natural Gas
                         Mmcfe/d   Percent      Wells     Oil     Gas     Liquids   Total     Amount     Percent
                         --------  --------   --------- ------- ------- ----------- -----  ------------  -------
                                                        (Mmbbl)  (Bcf)    (Mmbbl)   (Bcfe) (in millions)
<S>                      <C>       <C>        <C>       <C>     <C>     <C>         <C>    <C>           <C>
Gulf of Mexico..........      69.5      45.5%     36      6.0    128.1      0.5     166.7    $  910.4      58.0%
Rocky Mountains.........      58.3      38.2     356     21.5     61.4       --     190.7       372.6      23.7
West Texas/Mid-
 Continent..............      12.4       8.2     309      7.2     14.9       --      57.9       115.9       7.4
Gulf Coast..............      12.3       8.1      34      0.1     38.3       --      39.0       172.0      10.9
                          --------  --------     ---     ----    -----      ---     -----    --------     -----
  Total.................     152.5     100.0%    735     34.8    242.7      0.5     454.3    $1,570.9     100.0%
                          ========  ========     ===     ====    =====      ===     =====    ========     =====
</TABLE>

 Gulf of Mexico

   The Gulf of Mexico represented 58% of our net present value as of December
31, 2000 and contributed 46% of our 2000 production. We have interests in
283,804 developed and 357,844 undeveloped gross acres in the Gulf of Mexico and
in 151 gross producing wells (approximately 36 net). The average net daily
production for 2000 was 69 Mmcfe. We had 167 Bcfe of proved reserves in the
Gulf of Mexico at December 31, 2000.

   In addition to a solid production base with numerous exploitation
opportunities within our developed acreage, the Gulf of Mexico provides us with
moderate-risk exploration targets. We drilled 18 exploratory wells in 2000,
while maintaining a two to three year inventory of exploration projects. We
have under license 3-D seismic data covering over 10,000 square miles (1,460
blocks) and 2-D seismic data covering 150,000 linear miles within the Gulf of
Mexico.

   West Cameron 180/198. The West Cameron 180/198 complex consists of all or a
portion of seven offshore blocks, including 30,000 gross developed and 5,000
gross undeveloped acres. This field had never been owned by an independent
producer prior to our purchase in October 1997. The complex is located 30 miles
offshore in 52 feet of water. It has produced approximately 1.7 trillion cubic
feet of natural gas, or Tcf, and 10 million barrels of oil, or Mmbbl, from over
20 separate producing zones since its discovery. The daily net production in
2000 (since the merger with EPGC) was 60 Mmcfe. As of December 31, 2000, we had
94 Bcfe of proved reserves in the complex.

   In addition to providing approximately 60% of our offshore production, the
complex holds significant drilling opportunities. We recently completed three
wells from the F Platform which will commence production during the first
quarter of 2001. In January 2001, we initiated a three-well drilling program
from our G Platform. Additionally, we expect to drill two exploration prospects
on the complex in 2001.

   West Cameron 613/614. We discovered this field in 1999 and it is located
approximately 120 miles offshore in 290 feet of water. A second exploration
well was drilled on the adjoining block in the third quarter of 2000. We
operate the field with a working interest of 50% and installed facilities and
commenced production in December 2000. The wells are currently producing 40
Mmcfe/d (16 Mmcfe/d net).

   High Island A-530. This field was discovered in 1999 and is located
approximately 110 miles offshore in 190 feet of water. We have a 25% non-
operated working interest and installed the platform and facilities and
commenced production in December 2000. Initial gross production was 10 Mmcfe/d
(approximately 2 Mmcfe/d net).


                                       19
<PAGE>

   Recent Discoveries. The following discoveries will have continued
exploitation activity in 2001:

  .  Grand Isle 103. This field is located approximately 48 miles offshore in
     275 feet of water and was discovered in the first half of 2000. We have
     a non-operated 21% working interest in the well. A second well was
     drilled in 2000 and we plan to install facilities and commence
     production in 2001.

  .  Vermilion 408. This field is located approximately 110 miles offshore in
     400 feet of water and was discovered in 1999. We have a 25% non-operated
     working interest in the field. The discovery well tested at 18 Mmcfe/d
     (approximately 3.5 Mmcfe/d net). A second well was drilled in this block
     in the third quarter of 2000. We anticipate installing facilities in
     2001 and commencing production in early 2002.

  .  West Cameron 370. This field was discovered in the fourth quarter of
     2000. It is located approximately 60 miles offshore in 78 feet of water.
     Westport operates with a 60% working interest. Following the discovery
     well we drilled three additional wells. We plan to install a platform
     and commence production late in the second quarter of 2001.

  .  East Cameron 104. This field was discovered in fourth quarter 2000. It
     is located approximately 30 miles offshore in 65 feet of water. Westport
     operates with a 60% working interest. Following the discovery well, a
     second well was drilled. We plan to install a platform and commence
     production in the third quarter of 2001.

  .  Eugene Island 45. This field was discovered in fourth quarter 2000. It
     is located approximately 12 miles offshore in 17 feet of water. Westport
     operates with a 60% working interest. Production is expected to commence
     late in the second quarter of 2001.

   Other Exploration Activity. Through the second quarter of 2001, we
anticipate drilling the following nine exploration prospects with an
additional six in the second half of the year:

<TABLE>
<CAPTION>
                                     Working   Operated/   Water  Net Estimated
   Prospect Location                 Interest Non-operated Depth   Well Costs
   -----------------                 -------- ------------ -----  -------------
                                       (%)                 (feet)   (millions)
   <S>                               <C>      <C>          <C>    <C>
   East Cameron 348.................    70      Operated    250       $1.8
   East Cameron 369.................    60      Operated    350        2.2
   High Island A348.................    66.7    Operated    280        2.0
   High Island 197..................    25    Non-operated   50        1.2
   Mississippi Canyon 322...........    25    Non-operated  700        0.7
   South Marsh Island 51............    40    Non-operated  100        1.2
   Vermillion 236...................    50    Non-operated  128        1.3
   West Cameron 198 A-5.............    62.5    Operated     52        2.5
   West Delta 143...................    50      Operated    350        2.8
</TABLE>

 Rocky Mountains

   The Rocky Mountain region represented 24% of our net present value as of
December 31, 2000 and contributed 38% of our 2000 production. We have
interests in 444,386 developed and 76,373 undeveloped gross acres in the
region and in 1,481 gross producing wells (approximately 356 net). The average
daily net production in 2000 was 58 Mmcfe. We had 191 Bcfe of proved reserves
in the Rocky Mountain region at December 31, 2000.

   The majority of the net present value of our Rocky Mountain region reserves
is concentrated in North Dakota and Wyoming. Our Rocky Mountain region
strategy is to develop lower-risk opportunities, exploit our infill,
horizontal and secondary/tertiary recovery opportunities, and make tactical
acquisitions to enhance current operations.

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

                                      20
<PAGE>

  .  South Fryburg Tyler Area. We expanded the Tyler sand production within
     the operated South Fryburg Tyler Unit by drilling two wells in 2000. An
     additional two wells are planned for 2001. On contiguous acreage
     adjacent to the unit a significant horizontal Fryburg play began
     unfolding in 2000. We participated in four wells during the year, two of
     which were producing by year-end at a gross rate in excess of 300 bbl/d.
     The remaining two were placed on production in January 2001 at similar
     rates. The play is expected to remain very active in 2001, with Westport
     participating in another eight to 10 wells. Our working interest ranges
     from 25% to 100%.

  .  Wiley Field. We operate this waterflood with a 54% working interest. In
     2000, we initiated a horizontal drilling program and successfully
     drilled five wells. At December 31, 2000, the wells were producing in
     excess of 700 bbl/d gross. In addition to the horizontal drilling, we
     increased water injection capacity. In the first half of 2001 an
     additional six to eight wells will be drilled with additional increases
     in water injection capacity.

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

   Wyoming. Our three primary areas of focus in Wyoming are the Big Horn basin,
the Powder River basin and the Greater Green River area.

  .  Big Horn Basin. Our most valuable onshore property based on net present
     value is the Gooseberry field. We own a 100% working interest (nearly
     90% net revenue interest) in this field, which consists of two
     waterflood units. Since acquiring the field in 1995, we have increased
     production by nearly 70% through the acquisition of proprietary 3-D
     seismic data, drilling of delineation wells, installation of the two
     waterfloods and the addition of shallower producing zones. We believe
     that the shallower producing zone also has potential for waterflooding.
     In 2001, we plan to drill two to three additional producers and to
     expand our water injection capacity.

  .  Powder River Basin. In 2000, we continued our coalbed methane drilling
     in the Bonepile area and initiated an alkaline surfactant polymer, or
     ASP, flood in our Mellott Ranch field. An ASP flood is a tertiary
     recovery technique that injects a mixture of chemicals into the
     reservoir to aid in the recovery of previously bypassed oil, thus
     increasing the ultimate produced reserves.

     Our recent activity in the Powder River basin has emphasized coalbed
     methane drilling. As a result of past acquisitions, we own more than
     30,000 net acres in this play. All of our drilling to date has been in
     the Bonepile area south of Gillette, Wyoming. In this area, the
     extensive Wyodak coal averages 75 feet in thickness at a depth of
     approximately 700 feet. Drilling, completion and facility costs are
     attractive, with the average well costing less than $80,000. In 2000, we
     operated the drilling of 56 wells and gross production on December 31,
     2000 was over 15 Mmcf/d (approximately 6 Mmcf/d net) of natural gas. In
     the first quarter of 2001 production was increased to 20 Mmcf/d. We plan
     to drill 45 to 50 additional wells in 2001. We participated in 17 wells,
     with working interests ranging from 7.5% to 19.5%, in the Big George,
     located approximately 10 to 12 miles southwest of Bonepile. The Big
     George averages over 50 feet in thickness and is at a depth of
     approximately 1,000 to 1,250 feet. At year-end all of the wells were
     still dewatering. We anticipate an additional 40 to 50 wells will be
     drilled in 2001.


                                       21
<PAGE>

     We have installed an ASP flood facility in our 100% owned and operated
     Mellott Ranch field. We plan to drill two additional wells in the field
     in 2001. ASP floods have been successfully implemented in two fields
     near Mellott Ranch. Based on field size and modeling of reservoir
     characteristics, we believe that we can achieve recovery increases as a
     result of applying ASP technology.

  .  Greater Green River Area. Exploitation of southwest Wyoming gas fields
     continues through infill development. We plan to drill 5 to 10 wells in
     the Standard Draw, Echo Springs, Fabian Ditch, Bruff and Triton fields
     in 2001.

 West Texas/Mid-Continent

   The West Texas/Mid-Continent area represented 7% of our net present value as
of December 31, 2000 and contributed 8% of our 2000 production. We have an
interest in 73,162 developed and 52,959 undeveloped gross acres and in 1,102
gross producing wells (approximately 309 net). The average net daily production
in 2000 was 12 Mmcfe. We had 58 Bcfe of proved reserves in this area at
December 31, 2000. Our West Texas/Mid-Continent region consists primarily of
properties in Texas, Oklahoma and Kansas, with reserves concentrated in the
Permian and Anadarko basins.

   We continue to exploit our 100% working interest ownership in the Howard
Glasscock field in the West Texas portion of the Permian Basin, which is our
most valuable asset in the region based on net present value. Based on the
results from adjacent successful waterfloods, we believe that additional
potential exists through the expansion and installation of waterfloods on our
leases. We expect activity to dramatically increase in 2001 as we expand
waterfloods on two of our leases, Otis Chalk and Kloh. We plan to drill 20 to
25 injectors and producers. Additionally, we plan to drill five to 10 producers
on several other leases. A significant number of opportunities for recompletion
and well deepenings have also been identified within our leasehold and we plan
to initiate a multi-year program to exploit these in 2001.

 Gulf Coast

   The Gulf Coast represented 11% of our net present value as of December 31,
2000 and contributed 8% of our fiscal year 2000 production. We have interests
in 67,329 developed and 2,111 undeveloped gross acres in the Gulf Coast and in
359 gross producing wells (approximately 34 net). The average net daily
production in 2000 was 12 Mmcfe. We had 39 Bcfe of proved reserves in the Gulf
Coast at December 31, 2000.

   Our activity in the Gulf Coast is focused on a multi-year drilling program
in Northern Louisiana. We acquired this interest in late 1998 and have
identified over 100 development locations in our four fields-- Ada, Sibley,
West Bryceland and Sailes. The 2,000 foot thick Hosston interval contains over
20 separate producing zones. Gross reserves per well average approximately 2
Bcf. In 2000, we participated in 33 wells, of which 30 were successful. We
anticipate drilling between 40 and 50 wells in this region in each of the next
two years.


                                       22
<PAGE>

Proved Reserves

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

<TABLE>
<CAPTION>
                                                         As of December 31,
                                                    -------------------------------
                                                       2000         1999     1998
                                                    ----------    -------- --------
<S>                                                 <C>           <C>      <C>
Oil (Mbbls)
 Developed.........................................     28,673      29,489   20,323
 Undeveloped.......................................      6,127       3,261    4,053
                                                    ----------    -------- --------
    Total..........................................     34,800      32,750   24,376
                                                    ==========    ======== ========
Natural Gas (Mmcf)
 Developed.........................................    183,872      82,639   80,327
 Undeveloped.......................................     58,839      36,531   19,957
                                                    ----------    -------- --------
    Total..........................................    242,711     119,170  100,284
                                                    ==========    ======== ========
Natural Gas Liquids (Mbbls)
 Developed.........................................        247          28       50
 Undeveloped.......................................        212           0        0
                                                    ----------    -------- --------
    Total..........................................        459          28       50
                                                    ==========    ======== ========
Total (Mmcfe)...........................               454,265     315,838  246,840
                                                    ==========    ======== ========
Present Value ($ in thousands)
 Developed......................................... $1,234,605    $300,328 $101,574
 Undeveloped.......................................    336,287      48,771    9,710
                                                    ----------    -------- --------
    Total.......................................... $1,570,892(1) $349,099 $111,284
                                                    ==========    ======== ========
 Standardized Measure ($ in thousands) (2)......... $1,098,399    $322,435 $104,606
</TABLE>
-------
(1) The difference in net present value from December 31, 1999 to December 31,
    2000 resulted almost entirely from (i) the addition of 134 Bcfe of proved
    reserves acquired in connection with the merger between Westport Oil and
    Gas and EPGC, (ii) the addition of 52 Bcfe as discoveries and extensions
    and (iii) the increase in commodity prices used to determine net present
    value (from $25.60 to $26.83 per bbl of oil and $2.30 to $9.52 per Mmbtu of
    natural gas).

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

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

                                       23
<PAGE>

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:

<TABLE>
<CAPTION>
                                                        Year Ended December 31,
                                                        -----------------------
                                                         2000    1999    1998
                                                        ------- ------- -------
     <S>                                                <C>     <C>     <C>
     Production Data:
     Oil (Mbbls).......................................   3,584   3,300   3,483
     Natural gas (Mmcf)................................  34,072  13,313   8,101
     NGL (Mbbls) (1)...................................      41
     Total Mmcfe.......................................  55,822  33,113  28,999
     Average Prices (2):
     Oil (per bbl)..................................... $ 27.98 $ 16.45 $ 10.79
     Natural gas (per Mcf).............................    4.21    2.19    1.79
     NGL (per bbl) (1).................................   21.02
     Total per Mcfe....................................    4.38    2.52    1.80
     Average Costs (per Mcfe):
     Lease operating expense........................... $  0.62 $  0.69 $  0.74
     General and administrative........................    0.14    0.16    0.20
     Depletion, depreciation and amortization..........    1.16    0.76    1.25
</TABLE>
--------
(1) Production of natural gas liquids was not meaningful for 1998 and 1999.
(2) Does not include the effects of hedging transactions.


Producing Wells

   The following table sets forth information at December 31, 2000 relating to
the producing wells in which we owned a working interest as of that date. We
also held royalty interests in 1,705 producing wells as of that date. Wells are
classified as oil or natural gas wells according to their predominant
production stream.

<TABLE>
<CAPTION>
                                                      Gross      Net    Average
                                                    Producing Producing Working
                                                      Wells     Wells   Interest
                                                    --------- --------- --------
<S>                                                 <C>       <C>       <C>
Crude oil and liquids..............................   1,812     578.7     31.9%
Natural gas........................................   1,281     156.2     12.2%
                                                      -----     -----
Total..............................................   3,093     734.9       --
                                                      =====     =====
</TABLE>

                                       24
<PAGE>

Acreage

   The following table sets forth information at December 31, 2000 relating to
acreage held by us. Developed acreage is assigned to producing wells.
Undeveloped acreage is acreage held under lease, permit, contract or option
that is not in a spacing unit for a producing well; including leasehold
interests identified for exploitation or exploratory drilling.

<TABLE>
<CAPTION>
                                                       Gross Acreage Net Acreage
                                                       ------------- -----------
<S>                                                    <C>           <C>
Developed:
  Gulf of Mexico......................................     283,804      65,315
  Rocky Mountains.....................................     444,386     167,721
  West Texas/Mid-Continent............................      73,162      26,551
  Gulf Coast..........................................      67,329       8,675
                                                         ---------     -------
  Total Developed.....................................     868,681     268,262
Undeveloped:
  Gulf of Mexico......................................     357,844     204,991
  Rocky Mountains.....................................      76,373      45,040
  West Texas/Mid Continent............................      52,959      10,355
  Gulf Coast..........................................       2,111         509
                                                         ---------     -------
  Total Undeveloped...................................     489,287     260,895
                                                         ---------     -------
    Total.............................................   1,357,968     529,157
                                                         =========     =======
</TABLE>

Drilling Results

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

<TABLE>
<CAPTION>
                                                                   Year Ended
                                                                  December 31,
                                                                 ---------------
                                                                 2000  1999 1998
                                                                 ----- ---- ----
<S>                                                              <C>   <C>  <C>
Development Wells:
  Productive
    Gross....................................................... 169.0 83.0 61.0
    Net.........................................................  40.0 28.2 14.5
  Dry
    Gross.......................................................   8.0    0  1.0
    Net.........................................................   1.7    0  0.6
Exploratory Wells:
  Productive
    Gross.......................................................  12.0  8.0  5.0
    Net.........................................................   5.8  1.4  1.9
  Dry
    Gross.......................................................   8.0  3.0  8.0
    Net.........................................................   3.4  1.3  1.8
</TABLE>

                                       25
<PAGE>

ITEM 3. LEGAL PROCEEDINGS

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

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.

                                       26
<PAGE>

                                    PART II

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

Price Range of Common Stock

   On October 19, 2000, we commenced an initial public offering of our common
stock at a price of $15.00 per share. Our common stock trades on the New York
Stock Exchange under the symbol "WRC." The following table sets forth the high
and low sales price as reported by the New York Stock Exchange for our common
stock for the periods indicated.

<TABLE>
<CAPTION>
                                                                 High     Low
                                                                ------- -------
<S>                                                             <C>     <C>
Fourth quarter 2000 (from October 20, 2000).................... $22.75  $14.875
First quarter 2001 (to March 1, 2001).......................... $23.375 $19.00
</TABLE>

   As of March 1, 2001, the closing price of our common stock was $21.00, there
were 38,419,041 shares of our common stock outstanding, and there were
approximately 23 holders of record of our 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 in the foreseeable future. Payment of any future dividends will
be at the discretion of our board of directors after taking into account many
factors, including our financial condition, operating results, current and
anticipated cash needs and plans for expansion. In addition, our ability to
declare and pay any dividends is currently restricted under our credit
agreement.

Recent Sales of Unregistered Securities

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

 .  In September 1999, 15,236,152 shares (adjusted to reflect subsequent stock
    splits effected prior to the merger between Westport Oil and Gas and EPGC)
    of our common stock were issued to Equitable Production Company in
    anticipation of the merger between Westport Oil and Gas and EPGC.

 .  In April 2000, 15,563,001, 33,750 and 33,750 shares of our common stock
    were issued to Westport Energy LLC, Donald D. Wolf Family Limited
    Partnership and Barth E. Whitham, respectively, in connection with the
    merger between Westport Oil and Gas and EPGC.

 .  In June 2000, each of James M. Funk, Alex M. Cranberg and William F.
    Wallace were issued 615 shares of our common stock in connection with his
    service as a director.

 .  In August 2000, each of Randy Stein and Peter R. Hearl were issued 535
    shares of our common stock in connection with his service as a director.

 .  In September 2000, Thomas A. Petrie purchased 13,018 shares of our common
    stock upon exercise of stock options granted to Mr. Petrie in connection
    with his service as a director.


                                       27
<PAGE>

The sales of securities in the transactions described above were deemed to be
exempt from registration under the Securities Act in reliance upon Section 4(2)
of the Securities Act for the following reasons:

 .  The transactions involved a limited group of recipients and did not
    involve any public offering of securities;

 .  We engaged in no general solicitations or advertising in connection with
    the transactions;

 .  The recipients of the securities in each such transaction represented
    their intentions to acquire the securities for investment only and not
    with a view to or in connection with any distribution thereof;

 .  Appropriate legends were affixed to the securities issued in such
    transactions; and

 .  All recipients were accredited investors within the definition of
    Regulation D, were financially sophisticated and had adequate access to
    the type of information about us that would be included in a registration
    statement.

Use of Proceeds

   On October 19, 2000, we commenced our initial public offering, which
consisted of 9,150,000 shares of our common stock, par value $0.01 per share
(including 2,650,000 shares offered by the selling stockholders) at $15.00 per
share pursuant to the registration statement (No. 333-40422) declared effective
by the SEC on October 19, 2000. The managing underwriters were Credit Suisse
First Boston Corporation, Donaldson, Lufkin & Jenrette Securities Corporation,
Lehman Brothers, Inc., Petrie Parkman & Co., Inc. and Banc of America
Securities LLC. Aggregate proceeds from the offering were $137,250,000
(including $39,750,000 payable to the selling stockholders). On November 22,
2000, the underwriters exercised their over-allotment option, which consisted
of 1,035,000 shares of our common stock at $15.00 per share. Aggregate proceeds
from the sale of shares pursuant to the over-allotment option were $15,525,000.
In connection with the offering, we incurred total expenses of approximately
$9.1 million, including underwriting discounts and commissions of approximately
$7.6 million and approximately $1.5 million in other expenses. After deducting
expenses of the offering, we received net offering proceeds of $103.9 million.
We used the net offering proceeds to repay a portion of the debt under our
credit agreement. No payments constituted direct or indirect payments to any of
our directors, officers or general partners or their associates, to persons
owning 10% or more of any class of our equity securities, or to any of our
affiliates.


                                       28
<PAGE>

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, 2000, were derived from our Consolidated
Financial Statements. 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
included elsewhere in this report.
<TABLE>
<CAPTION>
                                      Year Ended December 31,
                             ------------------------------------------------
                               2000       1999      1998      1997     1996
                             --------    -------  --------  --------  -------
                               (in thousands, except per share data)
<S>                          <C>         <C>      <C>       <C>       <C>
Statement of Operations
 Data:
Revenues.................... $220,042    $75,488  $ 52,355  $ 63,870  $35,141
Operating costs and
 expenses:
  Lease operating expense...   34,397     22,916    21,554    19,583   10,716
  Production taxes..........   10,631      5,742     3,888     5,923    3,561
  Transportation costs......    3,034      1,725       850       781       --
  Exploration...............   12,790      7,314    14,664     7,424    1,054
  Depletion, depreciation
   and amortization.........   64,856     25,210    36,264    23,659    8,325
  Impairment of proved
   properties...............    2,911      3,072     8,794     5,765      442
  Impairment of unproved
   properties...............    5,124      2,273     1,898       380       --
  Stock compensation
   expense..................    5,539(1)      --        --        --       --
  General and
   administrative...........    7,542      5,297     5,913     5,316    2,655
                             --------    -------  --------  --------  -------
    Total operating
     expenses...............  146,824     73,549    93,825    68,831   26,753
                             --------    -------  --------  --------  -------
    Operating income
     (loss).................   73,218      1,939   (41,470)   (4,961)   8,388
Other income (expense):
  Interest expense..........   (9,731)    (9,207)   (8,323)   (5,635)  (2,774)
  Interest income...........    1,230        489       403       309      313
  Gain (loss) on sale of
   assets, net..............    3,130      3,637        --       (13)     128
  Derivative gain (loss) and
   other....................     (587)        16        29       (54)      44
                             --------    -------  --------  --------  -------
  Income (loss) before
   income taxes.............   67,260     (3,126)  (49,361)  (10,354)   6,099
  Benefit (provision) for
   income taxes.............  (23,724)        --        --       973  (2,289)
                             --------    -------  --------  --------  -------
  Net income (loss)......... $ 43,536    $(3,126) $(49,361) $ (9,381) $ 3,810
                             ========    =======  ========  ========  =======
Weighted average number of
 common shares outstanding:
  Basic.....................   28,296     14,727    11,004     9,326    4,531
                             ========    =======  ========  ========  =======
  Diluted...................   28,645     14,727    11,004     9,326    4,531
                             ========    =======  ========  ========  =======
Net income (loss) per
 common share:
  Basic..................... $   1.54    $ (0.21) $  (4.49) $  (1.01)  $ 0.84
                             ========    =======  ========  ========  =======
  Diluted................... $   1.52    $ (0.21) $  (4.49) $  (1.01) $  0.84
                             ========    =======  ========  ========  =======
Other Financial Data:
EBITDAX(2).................. $165,567    $43,950  $ 20,582  $ 32,509  $18,694
Net cash provided by
 operating activities.......  143,429     21,279     7,622    24,146   15,921
Net cash provided by (used
 in) investing activities... (140,169)    17,981  (113,019) (150,441) (24,040)
Net cash provided by (used
 in) financing activities...   (2,581)   (29,933)  104,667   126,675   13,735
Capital expenditures........  146,086     14,005   113,008   153,791   24,023
Balance Sheet Data
 (as of period end):
Cash........................ $ 20,154    $19,475  $ 10,148  $ 10,878  $10,497
Working capital (deficit)...   20,487     12,837   (30,993)    4,296    7,797
Total assets................  551,831    271,477   302,302   245,394  117,597
Total long-term debt........      162    105,462   121,333    92,128   25,462
Total debt..................      162    106,795   153,128    93,462   26,795
Stockholders' equity........  458,056    140,011   126,737   131,098   80,471
</TABLE>

                                       29
<PAGE>

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

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

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

General

   Acquisitions over the past three years have facilitated our growth. On April
7, 2000, Westport Oil and Gas consummated a merger with EPGC, pursuant to which
Westport Oil and Gas acquired the Gulf of Mexico properties of Equitable
Production Company that were held by EPGC. In connection with this merger, we
issued 15.2 million shares of common stock, paid cash in the amount of $50.0
million and assumed liabilities in the amount of $1.8 million. We increased our
proved reserves by 134 Bcfe and our Gulf of Mexico leasehold by 157,000 net
acres. On October 15, 1998, Westport Oil and Gas acquired an undivided 31%
interest in the individual assets and liabilities of Total Minatome
Corporation, which consist primarily of working interests in oil and natural
gas properties, for a total purchase price of $56.0 million. The oil and
natural gas properties acquired from Total Minatome are located principally in
the Gulf Coast, Rocky Mountains and Gulf of Mexico. Through this acquisition,
reserves increased by 64 Bcfe and natural gas/oil mix shifted at the time to
41%/59%. On January 31, 1997, Westport Oil and Gas consummated the Axem
transaction, an acquisition of oil and natural gas properties located in the
Rocky Mountains and the West Texas/Mid-Continent area, for a total purchase
price of $108.0 million. Through this acquisition, reserves increased nearly 82
Bcfe. Each of the noted acquisitions were accounted for using purchase
accounting and the results of the acquired properties were consolidated from
the respective closing dates. During 1995 and 1996, Westport Oil and Gas made
acquisitions totaling approximately $84.0 million from Conoco, Chevron, Mobil,
Koch and others establishing its operations and reserve base in the Rocky
Mountains and West Texas/Mid-Continent areas.

   We incurred net losses of $49.4 million and $3.1 million in 1998 and 1999,
respectively, and net income of $43.5 million in 2000. Results of operations
are significantly impacted by the price of oil and natural gas. During 1998,
oil and natural gas prices were lower than prices to be realized in 1999 and
2000. Since the second quarter of 1999, oil and natural gas prices have
significantly increased. The prices we receive for our oil vary from NYMEX
prices based on the location and quality of the crude oil. The prices we
receive for our natural gas are based on Henry Hub prices reduced by
transportation and processing fees.


                                       30
<PAGE>

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

   Oil and natural gas production costs are composed of lease operating
expense, production taxes and transportation costs. Lease operating expense
consists of pumpers' salaries, utilities, maintenance and other costs necessary
to operate our producing properties. In general, lease operating expense per
unit of production is lower on our offshore properties and does not fluctuate
proportionately with our production. Production taxes are assessed by
applicable taxing authorities as a percentage of revenues. However, properties
located in Federal waters offshore are generally not subject to production
taxes. We expect production taxes as a percentage of revenue to decline as we
increase production from our Gulf of Mexico properties. Transportation costs
are comprised of costs paid to a carrier to deliver oil or natural gas to a
specified delivery point. We then receive from the purchaser a price for oil or
natural gas plus transportation costs.

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

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

   We assess our proved properties on a field-by-field basis for impairment, in
accordance with the provisions of Statement of Financial Accounting Standards
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of," whenever events or circumstances indicate that the
capitalized costs of oil and natural gas properties may not be recoverable.
When making such assessments, we compare the expected undiscounted future net
revenues on a field-by-field basis with the related net capitalized costs at
the end of each period. When the net capitalized costs exceed the undiscounted
future net revenues, the cost of the property is written down to "fair value,"
which is determined using discounted future net revenues based on escalated
prices. Impairments for the years ended December 31, 2000, 1999 and 1998 were
calculated based on the following prices: oil prices per barrel of $24.70,
$20.84 and $13.00, respectively; and natural gas prices per Mcf of $4.48, $2.36
and $1.95, respectively. Oil prices were escalated annually at 2.5%, 2.5% and
2.0% in 2000, 1999 and 1998, respectively. Gas prices were escalated annually
at 2.5%, 2.5% and 3.0% in 2000, 1999 and 1998, respectively. Estimates of
declining production were based on estimates by independent reserve engineers
and estimated operating costs and severance taxes were based on past
experience. Operating and future development costs were escalated annually at
2.5%, 2.5% and 3.0% in 2000 1999 and 1998, respectively. Reserve categories
used in the impairment analysis for all periods considered all categories of
proven reserves and probable and possible reserves, which were risk-adjusted
based on our drilling plans and history of successfully developing those types
of reserves. Estimates of reserve volumes for each reserve category for each
year were prepared principally by independent reserve engineers.

                                       31
<PAGE>

   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 a one-time expense related to the repurchase
of employee stock options in March 2000.

   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 and Houston offices. While we
expect such costs to increase with our growth, we expect such increases to be
proportionately smaller than our production growth.

Results of Operations

   On April 7, 2000, Westport Oil and Gas merged with EPGC. This merger between
EPGC and Westport Oil and Gas resulted in Westport Oil and Gas becoming a
wholly-owned subsidiary of EPGC, which subsequently changed its name to
Westport Resources Corporation. As a result of the merger, the stockholders of
Westport Oil and Gas became the majority stockholders of EPGC, and the senior
management team of Westport Oil and Gas became the management team for the
combined company, complemented by certain key managers from EPGC. The merger
was accounted for using purchase accounting with Westport Oil and Gas as of the
April 7, 2000 closing date. The discussion below includes a comparison of our
results of operations for the years ended December 31, 2000, 1999 and 1998.

   Revenues. Oil and natural gas revenues for 2000 increased by $144.5 million,
or 191%, from $75.5 million to $220.0 million. Production from the acquired
EPGC properties accounted for $95.3 million of the increase and the remaining
increase resulted from increases of 70% and 92% in realized oil and natural gas
prices, respectively. The increase of 22,709 Mmcfe in production volumes from
33,113 Mmcfe in 1999 to 55,822 Mmcfe in 2000 was primarily due to 21,260 Mmcfe
from the acquired EPGC properties. Hedging transactions had the effect of
reducing oil and natural gas revenues by $24.6 million and $7.9 million, or
$0.44 and $0.24 per Mcfe, for the year ended December 31, 2000 and 1999,
respectively.

   Oil and natural gas revenues for 1999 increased by $23.1 million, or 44%,
from $52.4 million to $75.5 million. This increase resulted from increases of
52% and 22% in realized oil and natural gas prices, respectively, and an
increase of 64% in natural gas production volumes partially offset by a
decrease of 5% in oil production volumes. The increase in production volumes
from 29.0 Bcfe to 33.1 Bcfe was primarily attributable to oil and natural gas
properties acquired from Total Minatome Corporation in October 1998. Hedging
transactions had the effect of reducing oil and natural gas revenues by $7.9
million, or $0.24 per Mcfe, in 1999 and increasing oil and natural gas revenues
by $0.3 million, or $0.01 per Mcfe, in 1998.

   Lease Operating Expense. Lease operating expense for 2000 increased by $11.5
million, or 50%, from $22.9 million to $34.4 million. Lease operating expenses
from the acquired EPGC properties accounted for $6.5 million of the increase.
On a per Mcfe basis, lease operating expense decreased from $0.69 to $0.62,
primarily due to the lower lease operating expense associated with the acquired
EPGC properties.

   Lease operating expense for 1999 increased by $1.3 million, or 6%, from
$21.6 million to $22.9 million. The increase in lease operating expense was the
result of additional expense recorded as a result of oil and natural gas
properties acquired from Total Minatome Corporation in October

                                       32
<PAGE>

1998, offset by uneconomic properties shut in during 1999 and sales of oil and
natural gas properties during 1999. On a per Mcfe basis, lease operating
expense decreased from $0.74 in 1998 to $0.69 in 1999. The cost per Mcfe
decreased because the acquired properties are primarily natural gas properties,
which have lower operating costs than oil properties.

   Production Taxes. Production taxes for 2000 increased by $4.9 million, or
85%, from $5.7 million to $10.6 million. The increase in production taxes is
primarily attributable to an increase in the average realized price of oil and
natural gas. As a percent of oil and natural gas revenues (excluding the
effects of hedges), production taxes decreased from 6.9% to 4.3%. The decrease
in production taxes as a percent of revenue is primarily the result of the EPGC
merger, which increased the number of offshore properties we own that are not
subject to production taxes.

   Production taxes for 1999 increased by $1.8 million, or 48%, from $3.9
million to $5.7 million. The increase in production taxes is primarily
attributable to an increase in the average realized price of oil and natural
gas. As a percent of oil and natural gas revenues (excluding the effects of
hedges), production taxes decreased from 7.5% in 1998 to 6.9% in 1999. The
decrease in production taxes as a percent of revenue is primarily the result of
the Total Minatome acquisition, which increased the number of offshore
properties we own that are not subject to production taxes.

   Transportation Costs. Transportation costs for 2000 increased by $1.3
million, or 76%, from $1.7 million to $3.0 million. Transportation costs from
the acquired EPGC properties accounted for $0.4 million of the increase. The
remaining increase was due to additional natural gas offshore wells and coalbed
methane wells that started producing in 2000, which incur higher costs to
process and transport the natural gas.

   Transportation costs for 1999 increased by $0.9 million, or 103%, from $0.8
million to $1.7 million. The increase in transportation costs was primarily the
result of natural gas properties located in northern Louisiana acquired from
Total Minatome Corporation in October 1998.

   Exploration Costs. Exploration costs for 2000 increased by $5.5 million, or
75%, from $7.3 million to $12.8 million. Exploration costs consist of $6.0
million of dry hole costs, $5.6 million of geological and geophysical costs and
$1.2 million of delay rentals. The increase was primarily due to $4.0 million
in additional dry hole costs as a result of five unsuccessful offshore
exploratory wells and three unsuccessful onshore exploratory wells drilled
during 2000. Geological and geophysical costs increased $1.0 million due to
increased offshore activity in 2000. Delay rentals accounted for $0.5 million
of the increase as a result of acquiring offshore leases in the EPGC merger.

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

   Depletion, Depreciation and Amortization (DD&A) Expense. DD&A expense
increased $39.7 million during 2000 from $25.2 million to $64.9 million.
Depletion related to the acquired EPGC properties caused DD&A expense to
increase $36.8 million. The remaining increase was due to the additions in oil
and natural gas properties during 2000. The average DD&A rate increased from
$0.76 per Mcfe during 1999 to $1.16 per Mcfe during 2000, a 53% increase in the
DD&A rate primarily due to the acquired offshore EPGC properties.

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

                                       33
<PAGE>

   Impairment of Proved Properties. During 2000, 1999 and 1998, we recognized
proved property impairments of $2.9 million, $3.1 million and $8.8 million,
respectively. Impairments recorded in 2000 were mainly the result of a decline
in the Company's oil and natural gas reserve value due to reserve volume
reductions in under performing fields in Wyoming, offshore and Louisiana. The
impairment recorded in 1999 was the result of a decrease in risk adjusted
probable reserves for the Ward Estes lease located in West Texas, which were
subsequently assigned to the operator of the lease in exchange for existing
producing property equipment and infrastructure owned by the operator. The
impairments recorded in 1998 were as follows: $4.9 million resulting from
depressed oil prices for certain long-lived oil properties located primarily in
the Rocky Mountains, $2.5 million resulting from depressed natural gas prices
for certain natural gas properties located in the Mid-Continent and $1.4
million based on the results of unsuccessful development drilling in the Mid-
Continent.

   Impairment of Unproved Properties. 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. In
1999, we recognized unproved property impairments of $2.3 million of which $1.3
million was associated with a prospect off the coast of Argentina and the
remaining $1.0 million for various leases held in North Dakota and Wyoming. In
1998, $1.7 million and $0.2 million were impaired for leases held in Michigan
and North Dakota, respectively.

   Stock Compensation Expense. During 2000, we recognized $5.5 million of stock
compensation expense composed of $2.1 million related to applying the
provisions of FASB Interpretation No 44, and a one-time stock compensation
charge of $3.4 million related to the repurchase of employee stock options in
connection with the EPGC merger. There was no stock compensation expense
recorded in 1999 and 1998.

   General and Administrative (G&A) Expense. G&A expense increased $2.2
million, or 42%, during 2000, from $5.3 million to $7.5 million. In connection
with the EPGC merger additional employees were hired in the Houston office
which accounted for a $3.4 million increase in G&A expense. Offsetting the
increase in G&A expense was a $0.6 million increase in overhead recoveries from
additional drilling in 2000 and $0.5 million additional costs incurred in 1999
related to closing down an office acquired in an acquisition. On a Mcfe basis,
G&A expense decreased 13% from $0.16 during 1999 to $0.14 during 2000.

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

   Other Income (Expense). Other income (expense) for 2000 was ($6.0 million)
compared to ($5.1 million) for 1999. The variance was primarily due to interest
expense which increased $0.5 million from $9.2 million in 1999 to $9.7 million
in 2000 as a result of $50 million in additional borrowings relating to the
EPGC merger.

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



                                       34
<PAGE>

   Income Taxes. We recorded income tax expense of $23.7 million for 2000 and
no income tax expense or benefit for 1999 resulting from a loss incurred in
1999. The difference between the income tax expense (benefit) for those periods
and the amounts that would be calculated by applying statutory income tax rates
to income before income taxes is due primarily to the credits from applying
enhanced recovery methods in 2000 and a deferred tax valuation allowance
recorded in 1999. As of December 31, 2000, we had a net deferred tax liability
of $38.5 million, which includes net operating loss carryforwards of $16.7
million.

   We recorded no income tax benefit in 1999 and 1998 resulting from losses
incurred in those years. The difference between the income tax benefit for
those years and the amount that would be calculated by applying statutory
income tax rates to loss before income taxes is due primarily to deferred tax
asset valuation allowances recorded in those years.

   Net Income. Net income for 2000 was $43.5 million compared to a net loss of
$3.1 million for 1999. The variance was primarily attributable to an increase
in revenues of $144.6 million, partially offset by increases of $39.6 million
in DD&A, $11.5 million in lease operating expenses and $23.7 million in income
tax expense.

   Net loss for 1999 was $3.1 million compared to $49.4 million for 1998. The
decrease in net loss was primarily attributable to an increase in revenues of
$23.1 million and decreases in exploration costs of $7.4 million and DD&A
expense of $11.1 million.

Liquidity and Capital Resources

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

   Cash flow from operating activities was $143.4 million for 2000 compared to
$21.3 million for 1999. Operating cash flow in 2000 increased compared to 1999
due to a 77% increase in commodity prices and as a result of the merger with
EPGC. Cash flow from operating activities increased $13.7 million from $7.6
million for 1998 to $21.3 million for 1999 due in part to a 14% increase in
production and a 40% increase in commodity prices.

   Cash flow used in investing activities was $140.2 million for 2000 compared
to cash flow generated from investing activities of $18.0 million for 1999.
Investing activities for 2000 include capital expenditures of $146.1 million,
primarily resulting from the merger with EPGC. Cash was generated in 1999 due
in part to $32.0 million of proceeds from sales of oil and natural gas
properties, which was offset by $14.0 million in additions to oil and natural
gas properties. Cash flow generated from investing activities was $18.0 million
for 1999 compared to cash flow used in investing activities of $113.0 million
for 1998. Cash used in 1998 related to acquisitions and exploitation and
exploration activities.

   Net cash used in financing activities was $2.6 million for 2000 compared to
net cash used in financing activities of $29.9 million for 1999. Financing
activities for 2000 reflect proceeds of $104.1 million from the sale of common
stock and borrowings of $50.0 million (utilized to consummate the merger with
EPGC) offset by repayments of long-term debt of $156.6 million. Cash flow used
in financing activities of $29.9 million for 1999 compared to cash flow from
financing activities of $104.7 million for 1998. Financing activities have
included primarily proceeds from the issuance of common stock to Westport
Energy LLC, proceeds from the issuance of long-term debt and repayment of long-
term debt.

   We generated EBITDAX of $165.6 million, $44.0 million and $20.6 million for
the years ended December 31, 2000, 1999 and1998, respectively. The increase in
EBITDAX from 1998 through 2000 is indicative of the successful implementation
of our reserve growth strategy along with our focus on

                                       35
<PAGE>

maintaining efficient operations with a low cost structure, coupled with an
increase in commodity prices. While we believe that EBITDAX may provide
additional information with respect to our ability to meet our future debt
service, capital expenditures and working capital requirements, certain
functional or legal requirements of our business may require us to utilize our
available funds for other purposes.

   We entered into a credit agreement as of April 7, 2000 among a syndicate of
banks led by Bank of America, N.A. in the aggregate amount of $325.0 million.
Our properties, which have been pledged as collateral securing outstanding
indebtedness under our credit agreement, could be foreclosed upon in the event
of our default thereunder. The amount available for borrowing under the credit
facility is limited to an initial borrowing base of $200.0 million as of April
7, 2000, which is redetermined semi-annually beginning on October 1, 2000. As
of December 31, 2000, we had a borrowing base of $200.0 million. The credit
agreement matures on April 4, 2003. Advances under the credit agreement can be
in the form of either a base rate loan or a Eurodollar loan. The interest on a
base rate loan is a fluctuating rate equal to (i) the higher of (a) the Federal
funds rate plus 0.5% and (b) Bank of America's prime rate, plus (ii) a margin
of either 0% or 0.25% depending on the amount outstanding under the credit
agreement. The interest on a Eurodollar loan is equal to the sum of (i) a
margin of between 1.00% and 1.75% depending on the amount outstanding under the
credit agreement and (ii) the rate obtained by dividing the Eurodollar rate by
one minus the reserve requirement for the Eurodollar loan.

   The borrowings under the credit agreement as of March 5, 2001 were $0.2
million. The credit agreement contains various covenants and restrictive
provisions, including with respect to the following matters:

  .  incurring other indebtedness;

  .  liens on our properties or assets;

  .  hedging contracts;

  .  mergers and issuances of securities;

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

  .  dividends and redemptions;

  .  investments and new businesses;

  .  credit extensions;

  .  transactions with affiliates; and

  .  prohibited contracts.

   In addition to these non-financial covenants, our credit agreement contains
two financial covenants: one that requires us to maintain a current ratio of
not less than 1.0 to 1.0 and another that requires us to maintain a ratio of
our EBITDA, as defined, to our consolidated interest expense for the period of
the preceding four consecutive fiscal quarters, beginning with the fiscal
quarter ended March 31, 2000, of not less than 2.5 to 1.0. As of December 31,
2000, we were in compliance with all credit agreement covenants. Our credit
agreement contains various events of default, upon the occurrence of which all
of our obligations under our credit agreement become immediately due and
payable. The events of default include, among others:

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

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


                                       36
<PAGE>

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

  .  a change of control of Westport;

  .  any material adverse change; and

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

   Any increases in the interest rates under our credit agreement can have an
adverse impact on our results of operations and cash flow. We use derivative
financial instruments, specifically interest rate swaps, to reduce and manage
interest rate risk. We have an interest rate swap contract for a period
commencing on July 30, 1998 and ending on March 11, 2002, for an aggregate
notional amount of $25 million with fixed interest rate of 5.58% payable by us
and the variable interest rate, a three-month LIBOR, payable by the third
party. As a result of our minimal debt balance at December 31, 2000, the
interest rate swap did not qualify as a hedge for accounting purposes. As such,
we recorded a gain of approximately $65,000 on the interest rate swap contract
based on December 31, 2000 market values. Based on the variable rate nature of
the majority of the debt, its fair value at December 31, 2000 approximated the
carrying amount of $0.2 million.

   Capital expenditures for 2000 included $60.0 million for exploitation and
$42.8 million for exploration. Approximately $107 million of our capital
expenditure budget for 2001 is allocated for exploitation and approximately $63
million allocated for exploration. Actual levels of capital expenditures may
vary significantly due to a variety of factors, including:

  .  drilling results;

  .  product prices;

  .  industry conditions and outlook; and

  .  future acquisitions of properties.

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

   We believe that our capital resources are adequate to meet the requirements
of our business. However, future cash flows are subject to a number of
variables including the level of production and oil and natural gas prices. We
cannot assure you that operations and other capital resources will provide cash
in sufficient amounts to maintain planned levels of capital expenditures or
that increased capital expenditures will not be undertaken.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

                                       37
<PAGE>

   Through March 1, 2001, we had entered into the following hedging
arrangements covering the period beginning January 1, 2001. One Mmbtu
approximates one Mcf of natural gas.

<TABLE>
<CAPTION>
                                                  Natural Gas Collars
                                       -----------------------------------------
                                       Average Daily Average NYMEX Average NYMEX
                                          Volume         Floor        Ceiling
   Time Period                            (Mmbtu)     Price/Mmbtu   Price/Mmbtu
   -----------                         ------------- ------------- -------------
   <S>                                 <C>           <C>           <C>
   1/1/01--12/31/01...................    12,000         $4.50         $6.00
   2/1/01--12/31/01...................    10,000          5.00          7.00
   3/1/01--12/31/01(1)................     6,000          5.50          8.00
</TABLE>
--------
(1) Natural gas collar entered into subsequent to December 31, 2000.

   While it is not our intention to terminate any of the arrangements, we
estimate we would have had to pay approximately $5.4 million to terminate the
existing arrangements on December 31, 2000 (including $0.7 million which has
been recorded as a derivative loss in the 2000 statement of operations).

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 has been no change in our independent accountants during the past two
fiscal years. 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.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

   The Company's Proxy Statement for its 2001 Annual Meeting of Stockholders,
when filed pursuant to Regulation 14A under the Securities Exchange Act of
1934, as amended (the "Exchange Act"), will be incorporated by reference in
this Annual Report on Form 10-K pursuant to General Instruction G(3) of Form
10-K and will provide the information required by Item 10.

ITEM 11. EXECUTIVE COMPENSATION

   The Company's Proxy Statement for its 2001 Annual Meeting of Stockholders,
when filed pursuant to Regulation 14A under the Exchange Act, will be
incorporated by reference in this Annual Report on Form 10-K pursuant to
General Instruction G(3) of Form 10-K and will provide the information required
by Item 11.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

   The Company's Proxy Statement for its 2001 Annual Meeting of Stockholders,
when filed pursuant to Regulation 14A under the Exchange Act, will be
incorporated by reference in this Annual Report on Form 10-K pursuant to
General Instruction G(3) of Form 10-K and will provide the information required
by Item 12.


                                       38
<PAGE>

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   The Company's Proxy Statement for its 2001 Annual Meeting of Stockholders,
when filed pursuant to Regulation 14A under the Exchange Act, will be
incorporated by reference in this Annual Report on Form 10-K pursuant to
General Instruction G(3) of Form 10-K and will provide the information required
by Item 13.

                                       39
<PAGE>


                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

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

    (1) Financial Statements
       Report of Independent Public Accountants
      Consolidated Balance Sheets as of December 31, 2000 and 1999
      Consolidated Statements of Operations for the years ended December
       31, 2000, 1999 and 1998
      Consolidated Statements of Stockholders' Equity for the years ended
       December 31, 2000, 1999 and 1998
      Consolidated Statements of Cash Flows for the years ended December
       31, 2000, 1999 and 1998
      Notes to Consolidated Financial Statements

    (2) Financial Statement Schedules

      All schedules have been omitted because the required information is
      insignificant or not applicable.

    (3) Exhibits

<TABLE>
<CAPTION>
  Exhibit
    No.                               Exhibits
  -------                             --------
 <C>       <S>                                                              <C>
  2.1      --Agreement and Plan of Merger, dated as of March 9, 2000, by
            and among Westport Oil and Gas Company, Inc., Westport Energy
            Corporation, Equitable Production Company, Equitable Produc-
            tion (Gulf) Company and EPGC Merger Sub Corporation (incorpo-
            rated by reference to Exhibit 2.1 to Form S-1 (Registration
            No. 333-40422) filed with the SEC on June 29, 2000).

  3.1      --Second Amended and Restated Certificate of Incorporation of
            the Registrant (incorporated by reference to Exhibit 3.3 to
            Form S-1 (Registration No. 333-40422) filed with the SEC on
            September 27, 2000).

  3.2      --Second Amended and Restated Bylaws of the Registrant (incor-
            porated by reference to Exhibit 3.4 to Form S-1 (Registration
            No. 333-40422) filed with the SEC on August 23, 2000).

  4        --Specimen Certificate for shares of Common Stock of the Reg-
            istrant (incorporated by reference to Exhibit 4 to Form S-1
            (Registration No. 333-40422) filed with the SEC on August 23,
            2000).

 10.1      --Credit Agreement, dated March 31, 2000, by and among
            Westport Oil and Gas Company, Inc. and a syndicate of banks
            led by Bank of America, N.A., as agent (incorporated by ref-
            erence to Exhibit 10.1 to Form S-1 (Registration No. 333-
            40422) filed with the SEC on June 29, 2000).

 10.2      --Shareholders' Agreement, dated as of March 9, 2000, by and
            among Equitable Production (Gulf) Company, Westport Energy
            Corporation and Equitable Production Company (incorporated by
            reference to Exhibit 10.2 to Form S-1 (Registration No. 333-
            40422) filed with the SEC on June 29, 2000).


 10.3      --Shareholders' Agreement, dated as of March 9, 2000, by and
            among Westport Energy Corporation, Barth E. Whitham and Don-
            ald D. Wolf Family Limited Partnership (incorporated by ref-
            erence to Exhibit 10.3 to Form S-1 (Registration No. 333-
            40422) filed with the SEC on June 29, 2000).
</TABLE>

                                       40
<PAGE>

<TABLE>
<CAPTION>
  Exhibit
    No.                                  Exhibits
  -------                                --------
 <C>       <S>
 10.4      --Westport Resources Corporation 2000 Stock Incentive Plan (incorpo-
            rated by reference to Exhibit 10.4 to Form S-1 (Registration No.
            333-40422) filed with the SEC on September 27, 2000).

 10.5      --Form of Indemnification Agreement (incorporated by reference to
            Exhibit 10.5 to Form S-1 (Registration No. 333-40422) filed with
            the SEC on June 29, 2000).

 10.6      --Westport Resources Corporation Annual Incentive Plan 2000 (incor-
            porated by reference to Exhibit 10.6 to Form S-1 (Registration No.
            333-40422) filed with the SEC on June 29, 2000).

 10.7      --Employment Agreement between Westport and Donald D. Wolf dated May
            8, 2000 (incorporated by reference to Exhibit 10.7 to Form S-1
            (Registration No. 333-40422) filed with the SEC on June 29, 2000).

 10.8      --Employment Agreement between Westport and Barth E. Whitham dated
            May 8, 2000 (incorporated by reference to Exhibit 10.8 to Form S-1
            (Registration No. 333-40422)
            filed with the SEC on June 29, 2000).

 21        --Subsidiaries of the Registrant (incorporated by reference to Ex-
            hibit 21 to Form S-1 (Registration No. 333-40422) filed with the
            SEC on June 29, 2000).

 23.1*     --Consent of Ryder Scott Company, L.P.

 23.2*     --Consent of Netherland, Sewell & Associates, Inc.
</TABLE>
--------
*filed herewith

(b)  Reports on Form 8-K

   We did not file any reports on Form 8-K in the quarter ended December 31,
2000.

                                       41
<PAGE>

                                   SIGNATURES

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

Date: March 15, 2001

                                          Westport Resources Corporation

                                            /s/ Donald D. Wolf
                                          By: _________________________________
                                            Donald D. Wolf
                                            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 and Barth E. Whitham, with full
power to act and with full power of substitution and resubstitution, our true
and lawful attorney-in-fact and agent with full power to execute in our name
and behalf in the capacities indicated below any and all amendments to this
report and to file the same, with all exhibits and other documents relating
thereto and hereby ratify and confirm all that such attorney-in-fact or his
substitute shall lawfully do or cause to be done by virtue hereof.

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed by the following persons in the capacities and on the
dates indicated below:

<TABLE>
<CAPTION>
             Signature                           Title                    Date
             ---------                           -----                    ----

<S>                                  <C>                           <C>
         /s/ Donald D. Wolf           Chairman, Chief Executive      March 15, 2001
____________________________________     Officer and Director
           Donald D. Wolf                (Principal Executive
                                               Officer)

        /s/ James H. Shonsey           Chief Financial Officer       March 15, 2001
____________________________________     (Principal Financial
          James H. Shonsey                     Officer)

      /s/ Kenneth D. Anderson         Vice President--Accounting     March 15, 2001
____________________________________     (Principal Accounting
        Kenneth D. Anderson                    Officer)

        /s/ Michael Russell                    Director              March 15, 2001
____________________________________
          Michael Russell

        /s/ Murry S. Gerber                    Director              March 15, 2001
____________________________________
          Murry S. Gerber

        /s/ David L. Porges                    Director              March 15, 2001
____________________________________
          David L. Porges

         /s/ James M. Funk                     Director              March 15, 2001
____________________________________
           James M. Funk

        /s/ Alex M. Cranberg                   Director              March 15, 2001
____________________________________
          Alex M. Cranberg

       /s/ William F. Wallace                  Director              March 15, 2001
____________________________________
         William F. Wallace

         /s/ Peter R. Hearl                    Director              March 15, 2001
____________________________________
           Peter R. Hearl

          /s/ Randy Stein                      Director              March 15, 2001
____________________________________
            Randy Stein
</TABLE>


                                       42
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<S>                                                                        <C>
Report of Independent Public Accountants.................................. F-2

Consolidated Balance Sheets as of December 31, 2000 and 1999.............. F-3

Consolidated Statements of Operations for the years ended December 31,
 2000, 1999 and 1998...................................................... F-4

Consolidated Statements of Stockholders' Equity for the years ended
 December 31, 2000, 1999 and 1998......................................... F-5

Consolidated Statements of Cash Flows for the years ended December 31,
 2000, 1999 and 1998...................................................... F-6

Notes to Consolidated Financial Statements................................ F-7
</TABLE>

                                      F-1
<PAGE>

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Westport Resources Corporation:

   We have audited the accompanying consolidated balance sheets of Westport
Resources Corporation (a Delaware corporation) and subsidiaries as of December
31, 2000 and 1999, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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, 2000 and 1999, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.

                                          ARTHUR ANDERSEN LLP

Denver, Colorado
February 23, 2001.


                                      F-2
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                               December 31,
                                                             ------------------
                                                               2000      1999
                                                             --------  --------
                                                              (in thousands,
                                                               except share
                          ASSETS                                   data)
<S>                                                          <C>       <C>
Current Assets:
  Cash and cash equivalents................................  $ 20,154  $ 19,475
  Accounts receivable, net.................................    49,200    14,645
  Prepaid expenses.........................................     4,670     1,712
                                                             --------  --------
    Total current assets...................................    74,024    35,832
                                                             --------  --------
Property and equipment, at cost:
  Oil and gas properties, successful efforts method:
   Proved properties.......................................   591,367   307,068
   Unproved properties.....................................    40,653    18,089
  Office furniture and equipment...........................     2,642     2,182
  Leasehold improvements...................................       501       488
                                                             --------  --------
                                                              635,163   327,827
Less accumulated depletion, depreciation and amortization..  (157,739)  (92,950)
                                                             --------  --------
    Net property and equipment.............................   477,424   234,877
                                                             --------  --------
Other assets...............................................       383       768
                                                             --------  --------
    Total assets...........................................  $551,831  $271,477
                                                             ========  ========
<CAPTION>
           LIABILITIES AND STOCKHOLDERS' EQUITY
<S>                                                          <C>       <C>
Current Liabilities:
  Accounts payable.........................................  $ 28,547  $  8,482
  Accrued expenses.........................................    19,827    10,574
  Ad valorem taxes payable.................................     4,788     2,606
  Income taxes payable.....................................       375       --
  Current portion of long-term debt........................       --      1,333
                                                             --------  --------
    Total current liabilities..............................    53,537    22,995
                                                             --------  --------
Long-term debt.............................................       162   105,462
Deferred income taxes......................................    38,503       --
Other liabilities..........................................     1,573     3,009
                                                             --------  --------
    Total liabilities......................................    93,775   131,466
                                                             --------  --------
Commitments and contingencies (Note 11)
Stockholders' equity:
  Common stock, $0.01 par value; 70,000,000 shares
   authorized;
   38,419,041 and 15,630,501 shares issued and outstanding
   at December 31, 2000 and 1999, respectively.............       384       156
  Additional paid-in capital...............................   472,576   198,295
  Accumulated deficit......................................   (14,904)  (58,440)
                                                             --------  --------
    Total stockholders' equity.............................   458,056   140,011
                                                             --------  --------
    Total liabilities and stockholders' equity.............  $551,831  $271,477
                                                             ========  ========
</TABLE>

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

                                      F-3
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                     For the Year Ended
                                                        December 31,
                                                  ---------------------------
                                                    2000     1999      1998
                                                  --------  -------  --------
                                                  (in thousands, except per
                                                       share amounts)
<S>                                               <C>       <C>      <C>
Operating revenues:
  Oil and natural gas sales...................... $220,042  $75,488  $ 52,355
                                                  --------  -------  --------
Operating expenses:
  Lease operating expense........................   34,397   22,916    21,554
  Production taxes...............................   10,631    5,742     3,888
  Transportation costs...........................    3,034    1,725       850
  Exploration....................................   12,790    7,314    14,664
  Depletion, depreciation and amortization.......   64,856   25,210    36,264
  Impairment of proved properties................    2,911    3,072     8,794
  Impairment of unproved properties..............    5,124    2,273     1,898
  Stock compensation expense.....................    5,539      --        --
  General and administrative.....................    7,542    5,297     5,913
                                                  --------  -------  --------
    Total operating expenses.....................  146,824   73,549    93,825
                                                  --------  -------  --------
    Operating income (loss)......................   73,218    1,939   (41,470)
                                                  --------  -------  --------
Other income (expense):
  Interest expense...............................   (9,731)  (9,207)   (8,323)
  Interest income................................    1,230      489       403
  Gain on sale of assets, net....................    3,130    3,637       --
  Derivative gain (loss) and other...............     (587)      16        29
                                                  --------  -------  --------
Income (loss) before income taxes................   67,260   (3,126)  (49,361)
                                                  --------  -------  --------
Provision for income taxes:
  Current........................................     (675)     --        --
  Deferred.......................................  (23,049)     --        --
                                                  --------  -------  --------
    Total provision for income taxes.............  (23,724)     --        --
                                                  --------  -------  --------
Net income (loss)................................ $ 43,536  $(3,126) $(49,361)
                                                  ========  =======  ========
Weighted average number of common shares
 outstanding:
    Basic........................................   28,296   14,727    11,004
                                                  ========  =======  ========
    Diluted......................................   28,645   14,727    11,004
                                                  ========  =======  ========
Net income (loss) per common share:
    Basic........................................ $   1.54  $ (0.21) $  (4.49)
                                                  ========  =======  ========
    Diluted...................................... $   1.52  $ (0.21) $  (4.49)
                                                  ========  =======  ========
</TABLE>

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

                                      F-4
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                 Common Stock  Additional
                                 -------------  Paid-in   Accumulated
                                 Shares Amount  Capital     Deficit    Total
                                 ------ ------ ---------- ----------- --------
                                                (in thousands)
<S>                              <C>    <C>    <C>        <C>         <C>
Balance at December 31, 1997....  9,638  $ 96   $136,955   $ (5,953)  $131,098
 Sale of common stock (Note 8)..  3,943    40     44,960         --     45,000
 Net loss.......................    --    --         --     (49,361)   (49,361)
                                 ------  ----   --------   --------   --------
Balance at December 31, 1998.... 13,581   136    181,915    (55,314)   126,737
 Sale of common stock (Note 8)..  2,050    20     16,380        --      16,400
 Net loss.......................    --    --         --      (3,126)    (3,126)
                                 ------  ----   --------   --------   --------
Balance at December 31, 1999.... 15,631   156    198,295    (58,440)   140,011
 Stock issuance for EPGC merger
  (Note 4)...................... 15,236   152    165,204        --     165,356
 Merger costs paid by principal
  stockholder...................    --    --       2,895        --       2,895
 Initial public offering of
  common stock..................  7,535    75    103,836        --     103,911
 Option plan compensation.......    --    --       2,156        --       2,156
 Stock options exercised........     13     1        140        --         141
 Stock issuance to directors....      4   --          50        --          50
 Net income.....................    --    --         --      43,536     43,536
                                 ------  ----   --------   --------   --------
Balance at December 31, 2000.... 38,419  $384   $472,576   $(14,904)  $458,056
                                 ======  ====   ========   ========   ========
</TABLE>


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

                                      F-5
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                      For the Year Ended
                                                         December 31,
                                                   ---------------------------
                                                     2000     1999      1998
                                                   --------  -------  --------
                                                        (in thousands)
<S>                                                <C>       <C>      <C>
Cash flows from operating activities:
  Net income (loss)............................... $ 43,536  $(3,126) $(49,361)
  Adjustments to reconcile net income (loss) to
   net cash provided by operating activities:
   Depletion, depreciation and amortization.......   64,856   25,210    36,264
   Exploratory dry hole costs.....................    6,020    2,032     9,487
   Impairment of proved properties................    2,911    3,072     8,794
   Impairment of unproved properties..............    5,124    2,273     1,898
   Stock compensation expense.....................    2,156      --        --
   Gain on sale of assets.........................   (3,130)  (3,637)      --
   Deferred income taxes..........................   23,049      --        --
   Director retainers settled for stock...........       50      --        --
   Changes in assets and liabilities, net of
    effects of acquisitions:
    Decrease (increase) in accounts receivable....  (28,678)  (6,448)   11,778
    Increase in prepaid expenses..................   (1,139)    (338)     (119)
    Increase (decrease) in accounts payable.......   17,930   (1,753)  (11,706)
    Increase in accrued expenses..................    9,622    4,236     1,817
    Increase (decrease) in ad valorem taxes
     payable......................................    2,183      337    (1,097)
    Increase in income taxes payable..............      375      --        --
    Decrease in other liabilities.................   (1,436)    (579)     (133)
                                                   --------  -------  --------
Net cash provided by operating activities.........  143,429   21,279     7,622
                                                   --------  -------  --------
Cash flows from investing activities:
  Additions to property and equipment............. (102,229) (14,005)  (49,630)
  Proceeds from sales of assets...................    6,259   31,994       299
  Merger with EPGC................................  (42,403)     --        --
  TMC acquisition, net of cash acquired...........      --       --    (56,348)
  Other acquisitions..............................   (1,454)     --     (7,030)
  Other...........................................     (342)      (8)     (310)
                                                   --------  -------  --------
Net cash provided by (used in) investing
 activities....................................... (140,169)  17,981  (113,019)
                                                   --------  -------  --------
Cash flows from financing activities:
  Proceeds from issuance of common stock, net.....  104,052   16,400    45,000
  Proceeds from issuance of long-term debt........   50,000      --     61,000
  Repayment of long-term debt..................... (156,633) (46,333)   (1,333)
                                                   --------  -------  --------
Net cash provided by (used in) financing
 activities.......................................   (2,581) (29,933)  104,667
                                                   --------  -------  --------
Net increase (decrease) in cash and cash
 equivalents......................................      679    9,327      (730)
Cash and cash equivalents, beginning of year......   19,475   10,148    10,878
                                                   --------  -------  --------
Cash and cash equivalents, end of year............ $ 20,154  $19,475  $ 10,148
                                                   ========  =======  ========
Supplemental cash flow information:
  Cash paid for interest.......................... $ 10,649  $ 9,575  $  7,472
                                                   ========  =======  ========
  Cash paid for income taxes...................... $    300  $   --   $    --
                                                   ========  =======  ========
Supplemental schedule of noncash investing and
 financing activities:
  Common stock issued in connection with the EPGC
   merger......................................... $165,356  $   --   $    --
                                                   ========  =======  ========
  Liabilities assumed in connection with the EPGC
   merger......................................... $  1,850  $   --   $    --
                                                   ========  =======  ========
  EPGC merger expenses paid by principal
   stockholder.................................... $  2,895  $   --   $    --
                                                   ========  =======  ========
</TABLE>

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

                                      F-6
<PAGE>

                         WESTPORT RESOURCES CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business and Summary of Significant Accounting Policies:

   On April 7, 2000, Westport Oil and Gas Company, Inc. merged with Equitable
Production (Gulf) Company ("EPGC"), an indirect subsidiary of Equitable
Resources, Inc. that held certain Gulf of Mexico assets (the "EPGC
Properties"). This transaction was effected by a merger (the "Merger") between
a newly-formed subsidiary of EPGC and Westport Oil and Gas Company, Inc.,
resulting in Westport Oil and Gas Company, Inc. becoming a wholly-owned
subsidiary of EPGC, which subsequently changed its name to Westport Resources
Corporation (the "Company"). Business activities of the Company include the
exploration for and production of oil and natural gas primarily in the Gulf of
Mexico, 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
equivalents approximates the fair value of such instruments.

  Revenue Recognition

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

  Natural Gas Balancing

   The Company uses the sales method of accounting for natural gas imbalances.
Under this method, revenue is recognized based on cash received rather than the
Company's proportionate share of natural gas produced. Natural gas imbalances
at December 31, 2000 and 1999 were not significant.

  Oil and Natural Gas Properties

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

   The Company follows the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of." SFAS No. 121 requires the Company
to assess the need for an impairment of capitalized costs of oil and natural
gas properties on a field-by-field basis. In applying this statement, the
Company compares the expected undiscounted future net revenues on a field-by-
field basis with the related net capitalized costs at the end of each period.
When the net capitalized costs exceed the undiscounted future net revenues, the
cost of the property is written down to "fair value," which is determined using
the discounted future net revenues on a field-by-field basis. In 2000, 1999 and
1998, the Company recorded proved property impairments of $2.9 million, $3.1
million and $8.8 million, respectively. Gains and losses resulting from the
disposition of proved properties are included in operations.


                                      F-7
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

   Capitalized costs of proved properties are depleted on a field-by-field
basis using the units-of-production method based upon proved oil and natural
gas reserves. The amortizable base of the Company's offshore properties
includes estimated dismantlement, restoration and abandonment costs, net of
estimated salvage values. In management's opinion, abandonment, restoration and
dismantlement costs from onshore properties generally approximate the residual
value of equipment, and therefore, no accrual for such costs has been recorded.

   Unproved properties are assessed periodically to determine whether
impairment has occurred. Sales proceeds from unproved oil and natural gas
properties are credited to related costs of the prospect sold until all such
costs are recovered and then to net gain or loss on sales of unproved oil and
natural gas properties. In 2000, 1999 and 1998, the Company recorded unproved
property impairments of $5.1 million, $2.3 million and $1.9 million,
respectively.

  Principles of Consolidation

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

  Earnings (Loss) per Common Share

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

  Consolidated Statements of Cash Flows

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

  Income Taxes

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

  Office Furniture and Equipment and Leasehold Improvements

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

                                      F-8
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


  Commodity Derivative Instruments and Hedging Activities

   The Company periodically enters into commodity derivative contracts and
fixed-price physical contracts to manage its exposure to oil and natural gas
price volatility. The Company primarily utilizes price swaps, futures contracts
or collars, which are generally placed with major financial institutions or
with counterparties of high credit quality that the Company believes are
minimal credit risks. The oil and natural gas reference prices of these
commodity derivatives contracts are based upon crude oil and natural gas
futures which have a high degree of historical correlation with actual prices
received by the Company. The Company accounts for its commodity derivatives
contracts using the hedge (deferral) method of accounting when the derivative
contracts are designated as hedges for accounting purposes and the mark to
market method if such derivative contracts do not qualify as hedges for
accounting purposes. Under the deferral method, gains and losses from
derivative contracts accounted for as hedges are recognized in oil and natural
gas revenue when the associated production occurs, and the resulting cash flows
are reported as cash flows from operating activities. Gains and losses from
commodity derivatives contracts accounted for as hedges that are closed before
the hedged production occurs are deferred until the production month originally
hedged. In the event of a loss of correlation between changes in oil and
natural gas reference prices under a commodity derivatives contract and actual
oil and natural gas prices, a gain or loss would be recognized currently to the
extent the commodity derivatives contract did not offset changes in actual oil
and natural gas prices. Under mark to market accounting, gains and losses on
derivative contracts not qualifying as hedges are reflected as derivative gains
(losses) in the accompanying statements of operations at each period end.

   At December 31, 2000, the Company had costless collar agreements for a total
of 7,720,000 Mmbtus of natural gas for the months of January through December
2001 at a floor price ranging from $4.50 per Mmbtu to $5.00 per Mmbtu and a
ceiling price ranging from $6.00 per Mmbtu to $7.00 per Mmbtu. One costless
collar agreement for 4,380,000 Mmbtus of natural gas for the months of January
through December 2001 was treated as a hedge for accounting purposes. The other
costless collar agreement for 3,340,000 Mmbtus of natural gas was for the
months of February through December. This gas collar did not qualify as a hedge
for accounting purposes.

   In accordance with SFAS No. 107, "Disclosures About Fair Value of Financial
Instruments," the Company has estimated the fair value of its commodity
derivative arrangements at December 31, 2000 utilizing the then-applicable
crude oil and natural gas strips. While it is not the Company's intention to
terminate any of the arrangements, it is estimated that the Company would have
to pay approximately $5.4 million to terminate the then-existing arrangements
on December 31, 2000 (including $0.7 million which has been recorded as a
derivative loss in the 2000 statement of operations). Due to the volatility of
crude oil and natural gas prices, the fair market value may not be
representative of the actual gain or loss that will be realized by the Company
in 2001.

   The Company recognized reductions of oil and natural gas revenues of $24.6
million and $7.9 million from hedging agreements in 2000 and 1999,
respectively. The Company recognized an increase in oil and natural gas
revenues of $298,000 from oil hedging agreements in 1998. The Company
recognized a derivative loss of $0.7 million in 2000 from commodity derivative
contracts that did not qualify as hedges for accounting purposes.

  Interest Rate Swap Agreement

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

                                      F-9
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The Company entered into an interest rate swap contract for a period
commencing on July 30, 1998 and ending on March 11, 2002. The contract, as
amended, is for an aggregate notional amount of $25 million with a fixed
interest rate of 5.58% payable by the Company and the variable interest rate, a
three-month LIBOR, payable by the third party. The difference between the
Company's fixed rates and the three-month LIBOR rate, which is reset every 90
days, is received or paid by the Company in arrears every 90 days and
recognized as an adjustment to interest expense. Accordingly, the Company
received $423,000 in 2000, paid $192,000 in 1999 and received $7,000 in
December, 1998. As a result of the Company's minimal debt balance at December
31, 2000, the interest rate swap did not qualify as a hedge for accounting
purposes. As such, the Company recorded a mark to market gain of approximately
$65,000 on the interest rate swap at December 31, 2000.

  Recent Pronouncements

   In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company must formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting. SFAS No. 133 is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000. Accordingly, upon adoption of SFAS No. 133 on
January 1, 2001, the Company recorded a hedging loss of approximately $3.1
million (net of tax effect of $1.6 million) as a cumulative effect of a change
in accounting principal in other comprehensive income for the fair market value
of derivative contracts designated as hedges. A corresponding entry of $4.7
million was recorded to derivative liability on the balance sheet.

   In September 2000, the Emerging Issues Task Force reached a consensus on
issue No. 00-10, "Accounting for Shipping and Handling Fees and Costs" ("EITF
No. 00-10"), which requires shipping and handling costs to be reflected as an
operating expense rather than as a reduction of revenue. The Company was
required to adopt the provisions of EITF No. 00-10 in the fourth quarter of
2000. Accordingly, the Company restated oil and natural gas revenues for all
periods presented to exclude the effects of transportation costs and recorded
such transportation costs as a separate line in the statements of operations.
Adoption of the provisions of EITF No. 00-10 had no impact on net income
(loss).

  Fair Value of Financial Instruments

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

  Use of Estimates

   The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.

                                      F-10
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


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

  Comprehensive Income

   The Company follows the provisions of SFAS No. 130, "Reporting Comprehensive
Income." SFAS No. 130 establishes standards for reporting and display of
comprehensive income and its components in a full set of general-purpose
financial statements. In addition to net income, comprehensive income includes
all changes in equity during a period, except those resulting from investments
and distributions to owner. The Company had no such changes in 2000, 1999 or
1998.

  Reclassifications

   Certain amounts reported in the prior year consolidated financial statements
have been reclassified to correspond to the December 31, 2000 presentation.

2. Initial Public Offering:

   On October 19, 2000, the Company completed an initial public offering of
9.15 million shares of common stock at $15.00 per share. The over allotment of
1.035 million additional shares was completed on November 22, 2000. Of the
total 10.185 million shares sold, 7.535 million shares were offered by the
Company and 2.65 million shares were offered by selling stockholders. After
payment of underwriting discounts and offering costs of $9.1 million, the
Company received net proceeds of $103.9 million. The proceeds were used to
repay a portion of the Company's outstanding debt.

   Prior to completion of the initial public offering, the Board of Directors
approved a restated certificate of incorporation in Delaware. Subsequent to
filing of the restated certificate, the Company split the common stock on a
three-for-two basis by way of a stock dividend. All par value, authorized
shares, common stock and common stock amounts have been retroactively restated
in the accompanying consolidated financial statements to reflect the stock
split.

3. Stock Option Repurchase:

   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. See Note 9.

4. Merger:

   The Merger was a non-taxable transaction accounted for using purchase
accounting with Westport Oil and Gas as the surviving entity. Westport
Resources Corporation paid $50 million in cash from bank borrowings, issued
15.236 million shares of common stock valued at $10.85 per share and assumed
liabilities of $1.85 million to consummate the Merger. The EPGC Properties
consist of 37 producing properties and 30 undeveloped blocks in the Gulf of
Mexico. The results of operations of EPGC have been included in the Company's
statement of operations since the closing date of April 7, 2000.

                                      F-11
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


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

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

The value of the common stock issued to consummate the Merger was determined
utilizing a valuation model to determine a Net Asset Value ("NAV") for each
company based on the pre-tax discounted future net revenues of the companies'
oil and gas reserves, derived from third party engineering reports, adjusted
for the companies' other assets and liabilities.

   In addition to the acquisition costs discussed above, the Company also
recorded deferred taxes of $15.5 million (net of the reversal of previously
established deferred tax valuation allowances of $21.9 million) for the
difference between the historical tax basis of the EPGC Properties and the
acquisition costs. Merger costs of $2.9 million paid by the Company's then
principal stockholder were also recorded as acquisition costs (with a
corresponding amount recorded to additional paid-in capital). The carrying
value of the oil and gas properties was subsequently reduced by approximately
$15 million for normal working capital adjustments for the period between the
effective date, October 1, 1999, to the closing date.

  Pro Forma Results of Operations (Unaudited)

   The following table reflects the unaudited pro forma results of operations
for the years ended December 31, 2000 and 1999 as though the Merger 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.

<TABLE>
<CAPTION>
                                                                For the Year
                                                               Ended December
                                                                     31,
                                                              -----------------
                                                                2000     1999
                                                              -------- --------
                                                               (in thousands,
                                                              except per share
                                                                    data)
   <S>                                                        <C>      <C>
   Revenues.................................................. $238,974 $140,360
   Net income................................................   46,860    9,452
   Basic net income per share................................     1.66     0.32
   Diluted net income per share..............................     1.64     0.31
</TABLE>

5. Concentration of Credit Risk:

   The Company has accounts with separate banks in Denver, Colorado and
Calgary, Canada. The Company invests substantially all available cash in an
overnight investment account consisting of U.S. Treasury obligations. At
December 31, 2000, the balance in the overnight investment account was $17.2
million.


                                      F-12
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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

6. Income Taxes:

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

<TABLE>
<CAPTION>
                                                                For the Year
                                                               Ended December
                                                                     31,
                                                              -----------------
                                                               2000   1999 1998
                                                              ------- ---- ----
                                                               (in thousands)
   <S>                                                        <C>     <C>  <C>
   Current:
     Federal................................................. $   675 $--  $--
     State...................................................     --   --   --
                                                              ------- ---- ----
                                                                  675  --   --
                                                              ------- ---- ----
   Deferred:
     Federal.................................................  22,289  --   --
     State...................................................     760  --   --
                                                              ------- ---- ----
                                                               23,049  --   --
                                                              ------- ---- ----
   Provision for income taxes................................ $23,724 $--  $--
                                                              ======= ==== ====
</TABLE>

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

<TABLE>
<CAPTION>
                                                      For the Year Ended
                                                         December 31,
                                                   ---------------------------
                                                     2000     1999      1998
                                                   --------  -------  --------
                                                        (in thousands)
   <S>                                             <C>       <C>      <C>
   Federal statutory rate......................... $ 23,541  $(1,063) $(16,783)
   State income taxes, net of Federal effect......      760     (103)   (1,630)
   Change in valuation allowance..................     (460)   1,177    18,425
   Other permanent differences....................     (117)     (11)      (12)
                                                   --------  -------  --------
                                                   $ 23,724  $   --   $    --
                                                   ========  =======  ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                                December 31,
                                                              -----------------
                                                                2000     1999
                                                              --------  -------
                                                               (in thousands)
   <S>                                                        <C>       <C>
   Oil and natural gas properties............................ $(45,031) $ 4,945
   Net operating loss carryforward...........................    5,853   17,443
   Alternative minimum tax credit............................      675      --
   Valuation allowance.......................................      --   (22,388)
                                                              --------  -------
   Net deferred tax liability................................ $(38,503) $   --
                                                              ========  =======
</TABLE>

   As of December 31, 2000, the Company had net operating loss carryforwards
for income tax purposes of approximately $16.7 million which expire between
2018 and 2019 and may be utilized to reduce future tax liability of the
Company. In first quarter 2000, the Company reduced its valuation

                                      F-13
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

allowance by approximately $460,000 based on a determination that a portion of
the Company's deferred tax assets would be realized in the future based on
taxable income generated by current operations. In second quarter 2000, the
Company reduced the remaining valuation allowance of $21.9 million as a result
of the Merger (see Note 4). The Company believes under existing tax law it will
be able to utilize its historical deductible temporary differences and
carryforwards to offset the taxable temporary differences resulting from the
Merger.

7. Long-Term Debt:

   Long-term debt consisted of:
<TABLE>
<CAPTION>
                                                                 December 31,
                                                                --------------
                                                                2000    1999
                                                                ----- --------
                                                                (in thousands)
   <S>                                                          <C>   <C>
   9% bank term note, payable in 24 equal quarterly
    installments of $333,333 plus interest, January 31, 1995
    through December 31, 2000.................................. $ --  $  1,333
   Bank line of credit due on April 4, 2003....................   162  105,462
                                                                ----- --------
                                                                  162  106,795
   Less current portion........................................   --    (1,333)
                                                                ----- --------
                                                                $ 162 $105,462
                                                                ===== ========
</TABLE>

   The Company entered into a credit agreement as of April 7, 2000 among a
syndicate of banks led by Bank of America, N.A. in the aggregate amount of
$325.0 million. The amount available for borrowing under the credit facility is
limited to an initial borrowing base of $200.0 million, but will be
redetermined semi-annually beginning on October 1, 2000. The credit agreement
matures on April 4, 2003 and is secured by substantially all of the Company's
oil and gas properties. Advances under the credit agreement can be in the form
of either a base rate loan or a Eurodollar loan. The interest on a base rate
loan is a fluctuating rate equal to (i) the higher of (a) the Federal funds
rate plus 0.5% and (b) Bank of America's prime rate, plus (ii) a margin of
either 0% or 0.25% depending on the amounts outstanding under the credit
agreement. The interest on a Eurodollar loan is equal to the sum of (i) a
margin of between 1.00% and 1.75% depending on the amount outstanding under the
credit agreement and (ii) the rate obtained by dividing the Eurodollar rate by
one minus the reserve requirement for the Eurodollar loan. The weighted average
rate in effect was 8.0% and 7.61% at December 31, 2000 and 1999, respectively.
Commitment fees under the credit agreement fluctuate from 0.25% to 0.40% based
on the ratio of the borrowing base to available borrowings. The credit
agreement 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 EBITDA, as defined, to consolidated
interest expense for the preceding four consecutive fiscal quarters of not less
than 2.5 to 1.0.

8. Stockholders' Equity:

   In 1998 and 1999, 3,942,758, and 2,050,001 shares of common stock were
purchased by the Company's then principal stockholder for share prices of
$11.41, and $8.00, respectively. The share prices reflected the estimated
market value of the Company's stock at the time of purchase. The estimated
market value was determined utilizing a valuation model that was based on the
pre tax discounted future net revenues from the Company's oil and gas reserves
adjusted for the Company's other assets and liabilities.

                                      F-14
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


9. Stock 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 4,110,813 shares. The exercise price, vesting and
duration of the options may vary and will be determined at the time of
issuance. During 2000, options to purchase 2,110,880 shares of the Company's
common stock were granted 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. The options vest ratably over two or
three years from the date of grant and have a term of 10 years. 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 (see Note 3). During 1999 and 1998, options to
purchase 597,600 and 93,750 shares of the Company's common stock were granted
under the Predecessor Plans at exercise prices between $8.00 and $15.78 per
share, which reflected the estimated fair market value of the shares at the
date of grant.

   In March 2000, the FASB issued Interpretation No. 44, "Accounting for
Certain Transactions Involving Stock Compensation." The Interpretation
clarifies (a) the definition of employee for purposes of applying APB Opinion
No. 25, (b) the criteria for determining whether a plan qualifies as a
noncompensatory plan, (c) the accounting consequence of various modifications
to the terms of previously fixed stock options or awards, and (d) the
accounting for an exchange of stock options and/or awards in a business
combination. The Interpretation was effective July 1, 2000, but certain
conclusions in the Interpretation cover specific events that occur after either
December 15, 1998, or January 12, 2000. To the extent that the Interpretation
covers events occurring during the period after December 15, 1998, or January
12, 2000, but before the effective date of July 1, 2000, the effects of
applying the Interpretation are recognized on a prospective basis from July 1,
2000. Under provisions of the Interpretation, we are required to account for
1,080,473 of the Replacement Options as variable awards from July 1, 2000 until
the date the options are exercised, forfeited or expire unexercised.
Compensation cost will be measured for the amount of any increases in our stock
price after July 1, 2000 and recognized over the remaining vesting period of
the options. Any decreases in our stock price subsequent to July 1, 2000 will
be recognized as a decrease in compensation cost, limited to the amount of
compensation cost previously recognized as a result of increases in our stock
price. Any adjustment to compensation cost for further changes in the stock
price after the award vests will be recognized immediately. As of December 31,
2000, 1,018,223 of the Replacement Options were still outstanding, which
resulted in $2.1 million of compensation cost recorded in the 2000 statement of
operations.


                                      F-15
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   A summary of the status of the Company's Stock Option Plan and Predecessor
Plans as of December 31, 2000, 1999 and 1998 and changes during the years ended
December 31, 2000, 1999 and 1998 are as follows:

<TABLE>
<CAPTION>
                                                              Shares    Weighted
                                                              Under     Average
                                                              Option    Exercise
                                                               Plan      Price
                                                            ----------  --------
<S>                                                         <C>         <C>
Balance at December 31, 1997...............................    986,723   $15.74
  Options granted..........................................     93,750    11.41
                                                            ----------
Balance at December 31, 1998...............................  1,080,473    15.37
  Options cancelled........................................   (333,563)   15.37
  Options granted..........................................    597,600     8.64
                                                            ----------
Balance at December 31, 1999...............................  1,344,510     8.29
  Options repurchased...................................... (1,344,510)   12.43
  Options granted..........................................  2,110,880    12.61
  Options forfeited........................................    (44,421)   10.85
  Options exercised........................................    (13,018)   10.85
                                                            ----------
Balance at December 31, 2000...............................  2,053,441    12.61
                                                            ==========
Options exercisable at December 31, 1998...................    397,619    15.65
                                                            ==========
Options exercisable at December 31, 1999...................    455,544     8.00
                                                            ==========
Options exercisable at December 31, 2000...................     29,516    10.85
                                                            ==========
</TABLE>

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

<TABLE>
<CAPTION>
                                                        For the Year Ended
                                                           December 31,
                                                     -------------------------
                                                      2000    1999      1998
                                                     ------- -------  --------
                                                          (in thousands,
                                                      except per share data)
<S>                                                  <C>     <C>      <C>
Net income (loss)
  As reported....................................... $43,536 $(3,126) $(49,361)
  Pro forma.........................................  41,885  (4,114)  (50,385)
Basic net income (loss) per common share
  As reported....................................... $  1.54 $ (0.21) $  (4.49)
  Pro forma.........................................    1.51   (0.28)    (4.58)
Diluted net income (loss) per common share
  As reported....................................... $  1.52 $ (0.21) $  (4.49)
  Pro forma.........................................    1.49   (0.28)    (4.58)
</TABLE>

   The weighted average fair value of options granted during the years ended
December 31, 2000, 1999 and 1998, calculated using the Black-Scholes option
pricing model, was $5.44, $4.21 and $2.69, respectively. The fair value of each
option granted is estimated with the following weighted

                                      F-16
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

average assumptions for grants in 2000, 1999 and 1998: risk-free interest rate
of 6.25%, 5.53% and 5.52%, respectively; no dividend yields; expected
volatility of 38.34%, 0.01% and 0.01%, respectively; and expected lives of 5
years.

10. Major Purchasers:

   The following purchasers accounted for 10% or more of the Company's oil and
gas sales for the years ended December 31, 2000, 1999 and 1998:
<TABLE>
<CAPTION>
                                                                  2000 1999 1998
                                                                  ---- ---- ----
   <S>                                                            <C>  <C>  <C>
   Dynegy Inc.................................................... 23%  --   --
   Conoco Inc.................................................... 14%  26%  26%
   Koch Oil Company.............................................. --   --   18%
   Energen Resources MAQ, Inc.................................... --   20%  17%
   EOTT Energy Corporation....................................... 13%  20%  --
</TABLE>

11. Commitments and Contingencies:

   At December 31, 2000, the Company had two leases covering office space under
noncancelable agreements which begin to expire in November, 2003. The minimum
annual rental payments under the leases are as follows (in thousands):

<TABLE>
<CAPTION>
   Year Ending December 31
   -----------------------
   <S>                                                                   <C>
   2001................................................................. $  502
   2002.................................................................    515
   2003.................................................................    482
                                                                         ------
                                                                         $1,499
                                                                         ======
</TABLE>

   Rent expense for the years ended December 31, 2000, 1999 and 1998 was
approximately $820,000, $497,000 and $652,000, respectively.

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

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

12. Producing Properties Acquisitions and Divestitures:

  Total Minatome Corporation Acquisition

   On October 15, 1998, the Company entered into an agreement ("Agreement")
with an industry partner ("Purchaser") in connection with a stock purchase
("Stock Purchase") agreement between

                                      F-17
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Purchaser and Total Minatome Corporation ("TMC") for the purchase of all of the
outstanding stock of TMC ("TMC Acquisition"), as an express third party
beneficiary of the rights of the Purchaser and the obligations of TMC under the
Stock Purchase. Pursuant to the Agreement, subsequent to the TMC Acquisition
the Purchaser assigned the Company a 31% interest in the individual assets and
liabilities of TMC ("TMC Property Acquisition"), which consist primarily of
working interests in oil and natural gas properties, for consideration of
approximately $56 million. The TMC Property Acquisition was funded by sales of
common stock to the Company's then principal stockholder and bank borrowings.
The TMC Property Acquisition was accounted for using the purchase method with
the purchase price allocated among proved and unproved oil and natural gas
properties and other assets and liabilities based on their relative fair
values. Revenue associated with the TMC Property Acquisition for the 3-month
period ended December 31, 1998 was approximately $5.5 million.

  Other Acquisitions

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

  Sale of Offshore Properties

   During 2000, the Company sold an interest in an oil and natural gas
development and exploration prospect located offshore in the Gulf of Mexico for
$6.2 million. The property had a book value of $2.9 million, and a $3.3 million
gain was recorded on the sale. Proceeds from the sale were used to reduce
borrowings under the credit agreement.

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

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 60%
of each participant's contributions up to 6% of the participant's compensation.
The Company contributed $155,000, $114,000 and $104,000, for the years ended
December 31, 2000, 1999, and 1998, respectively.

                                      F-18
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


14. Supplemental Information Related to Oil and Gas Activities:

   The following tables set forth certain historical costs and costs incurred
related to the Company's oil and natural gas producing activities:
<TABLE>
<CAPTION>
                                                         December 31,
                                                  ----------------------------
                                                    2000      1999      1998
                                                  --------  --------  --------
                                                        (in thousands)
<S>                                               <C>       <C>       <C>
Capitalized costs
  Proved oil and natural gas properties.......... $591,367  $307,068  $316,243
  Unproved oil and natural gas properties........   40,653    18,089    32,611
                                                  --------  --------  --------
    Total oil and natural gas properties.........  632,020   325,157   348,854
  Less: Accumulated depletion, depreciation and
   amortization.................................. (155,752)  (91,325)  (73,096)
                                                  --------  --------  --------
    Net capitalized costs........................ $476,268  $233,832  $275,758
                                                  ========  ========  ========
</TABLE>

<TABLE>
<CAPTION>
                                                         For the Year Ended
                                                            December 31,
                                                      -------------------------
                                                        2000    1999     1998
                                                      -------- ------- --------
                                                           (in thousands)
<S>                                                   <C>      <C>     <C>
Costs incurred
  Proved property acquisition costs.................. $182,944 $   --  $ 61,938
  Unproved property acquisition costs................   31,821   2,336   15,873
  Exploration costs..................................   34,622   7,958   19,806
  Development costs..................................   58,958   3,695   15,164
                                                      -------- ------- --------
    Total............................................ $308,345 $13,989 $112,781
                                                      ======== ======= ========
</TABLE>

  Oil and Gas Reserve Information (Unaudited)

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

   Estimates of total proved and proved developed reserves at December 31, 2000
were prepared by Ryder Scott Company, L.P. 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. Estimates of total proved and proved developed reserves at
December 31, 1999 and 1998 were prepared by Ryder Scott Company, L.P. Proved
reserves are estimated quantities of crude oil and natural gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are proved reserves that can be recovered
through existing wells with existing equipment and operating methods.
Substantially all of the Company's oil and natural gas reserves are located in
the United States and the Gulf of Mexico.

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

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

                                      F-19
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


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

  3. The future cash flows are reduced by estimated production costs and
  costs to develop and produce the proved reserves, all based on year-end
  economic conditions and by the estimated effect of future income taxes
  based on statutory income tax rates in effect at each year end, the
  Company's tax basis in its proved oil and natural gas properties and the
  effect of net operating loss, investment tax credit and other
  carryforwards.

   The Standardized Measure of discounted future net cash flows does not
purport to present, nor should it be interpreted to present, the fair value of
the Company's oil and natural gas reserves. An estimate of fair value would
also take into account, among other things, the recovery of reserves not
presently classified as proved, anticipated future changes in prices and costs
and a discount factor more representative of the time value of money and the
risks inherent in reserve estimates.

   Quantities of Oil and Gas Reserves (Unaudited)

   The following table presents estimates of the Company's net proved and
proved developed oil and gas reserves:
<TABLE>
<CAPTION>
                                                                 Oil      Gas
                                                                (Mbls)   (Mmcf)
                                                                ------  -------
   <S>                                                          <C>     <C>
   Proved reserves at December 31, 1997........................ 27,991   28,791
     Revisions of previous estimates........................... (2,905)   5,618
     Discoveries...............................................  1,882    5,116
     Purchase of minerals in place.............................  1,212   70,395
     Sales of minerals in place................................   (321)  (1,235)
     Production................................................ (3,483)  (8,101)
                                                                ------  -------
   Proved reserves at December 31, 1998........................ 24,376  100,584
     Revisions of previous estimates........................... 13,814   20,332
     Discoveries...............................................    708   24,250
     Purchase of minerals in place.............................    --       --
     Sales of minerals in place................................ (2,848) (12,515)
     Production................................................ (3,300) (13,313)
                                                                ------  -------
   Proved reserves at December 31, 1999........................ 32,750  119,338
     Revisions of previous estimates...........................  1,417   10,662
     Discoveries...............................................  3,135   33,445
     Purchase of minerals in place.............................  3,249  116,783
     Sales of minerals in place................................ (2,167)    (447)
     Production................................................ (3,584) (34,316)
                                                                ------  -------
   Proved reserves at December 31, 2000........................ 34,800  245,465
                                                                ======  =======
   Proved developed reserves at December 31, 1998.............. 20,323   80,627
                                                                ======  =======
   Proved developed reserves at December 31, 1999.............. 29,489   82,807
                                                                ======  =======
   Proved developed reserves at December 31, 2000.............. 28,673  185,354
                                                                ======  =======
</TABLE>

                                      F-20
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves (Unaudited)
<TABLE>
<CAPTION>
                                                       December 31,
                                               ------------------------------
                                                  2000       1999      1998
                                               ----------  --------  --------
                                                      (in thousands)
   <S>                                         <C>         <C>       <C>
   Future cash flows.......................... $2,993,022  $986,992  $392,158
   Future production costs....................   (546,358) (362,648) (170,279)
   Future development costs...................   (119,415)  (44,552)  (42,957)
                                               ----------  --------  --------
   Future net cash flows before tax...........  2,327,249   579,792   178,922
   Future income taxes........................   (691,048) (100,178)   (4,766)
                                               ----------  --------  --------
   Future net cash flows after tax............  1,636,201   479,614   174,156
   Annual discount at 10%.....................   (537,802) (157,179)  (69,550)
                                               ----------  --------  --------
   Standardized measure of discounted future
    net cash flows............................ $1,098,399  $322,435  $104,606
                                               ==========  ========  ========
   Discounted future net cash flows before
    income taxes.............................. $1,570,892  $349,099  $111,284
                                               ==========  ========  ========
</TABLE>

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

<TABLE>
<CAPTION>
                                                 For the Year Ended December
                                                             31,
                                                 -----------------------------
                                                   2000       1999      1998
                                                 ---------  --------  --------
                                                       (in thousands)
   <S>                                           <C>        <C>       <C>
   Oil and natural gas sales, net of production
    costs......................................  $(196,608) $(53,009) $(25,765)
   Net changes in anticipated prices and
    production cost............................    369,244   147,678   (65,975)
   Extensions and discoveries, less related
    costs......................................    228,685    19,831     6,536
   Changes in estimated future development
    costs......................................    (15,807)  (11,691)    5,114
   Previously estimated development costs
    incurred...................................     16,827     6,175     6,865
   Net change in income taxes..................   (445,830)  (19,985)   (4,821)
   Purchase of minerals in place...............    748,854       --     41,513
   Sales of minerals in place..................     (3,205)   (2,896)   (2,301)
   Accretion of discount.......................     34,910    11,129    15,541
   Revision of quantity estimates..............     48,384   130,750    (5,822)
   Changes in production rates and other.......     (9,490)  (10,153)  (19,829)
                                                 ---------  --------  --------
     Change in standardized measure............  $ 775,964  $217,829  $(48,944)
                                                 =========  ========  ========
</TABLE>

                                      F-21
<PAGE>

                         WESTPORT RESOURCES CORPORATION

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


15. Supplemental Quarterly Financial Information (Unaudited)

<TABLE>
<CAPTION>
                                    First   Second    Third  Fourth     Full
2000                               Quarter  Quarter  Quarter Quarter    Year
----                               -------  -------  ------- -------  --------
                                   (in thousands, except per share amounts)
<S>                                <C>      <C>      <C>     <C>      <C>
Total revenues.................... $25,462  $53,154  $64,075 $77,351  $220,042
Gross profit (1).................. $16,094  $41,330  $52,230 $62,326  $171,980
Net income........................ $ 1,397  $ 9,209  $19,004 $13,926  $ 43,536
Net income per share (2)
  Basic........................... $  0.13  $  0.40  $  0.62 $  0.38  $   1.54
  Diluted......................... $  0.13  $  0.40  $  0.61 $  0.37  $   1.52

1999
----
Total revenues.................... $15,150  $17,516  $19,784 $23,038  $ 75,488
Gross profit (1).................. $ 8,560  $11,006  $11,477 $14,062  $ 45,105
Net income (loss)................. $  (159) $(1,617) $ 2,287 $(3,637) $ (3,126)
Net income (loss) per share (2)
  Basic........................... $ (0.02) $ (0.12) $  0.15 $ (0.23) $  (0.21)
  Diluted......................... $ (0.02) $ (0.12) $  0.14 $ (0.23) $  (0.21)
</TABLE>
--------
(1) Gross profit is computed as the excess of oil and natural gas revenues 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 (loss) per share as each period's
    computation is based on the weighted average number of common shares
    outstanding during the period.

                                      F-22