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

                                   FORM 10-KSB

[X]                ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934

                   For the fiscal year ended December 31, 2000

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

                 For the transition period from ______ to ______

                         Commission file number: 0-22782

                            ESENJAY EXPLORATION, INC.
              (Exact name of small business issuer in its charter)

         DELAWARE                                      73-1421000
  (State of incorporation)               (I.R.S. Employer Identification Number)

                         500 N. WATER STREET, SUITE 1100
                           CORPUS CHRISTI, TEXAS 78471
    (Address of registrant's principal executive offices, including zip code)

       Registrant's telephone number, including area code: (361) 883-7464

         Securities registered under Section 12(b) of the Exchange Act:

<TABLE>
<CAPTION>
                                                 NAME OF EACH EXCHANGE
      TITLE OF EACH CLASS                         ON WHICH REGISTERED
<S>                                              <C>
            None                                         None
</TABLE>

         Securities registered under Section 12(g) of the Exchange Act:

                                  COMMON STOCK
                     SERIES B COMMON STOCK PURCHASE WARRANTS

         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-B 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-KSB or any amendment to this Form 10-KSB. [X]

         State issuer's revenues for its most recent fiscal year: $34,674,753

         The aggregate market value of the voting stock held by
non-affiliates of the registrant (treating all executive officers and
directors of the registrant, for this purpose, as if they may be affiliates
of the registrant) was approximately $44,641,018 on March 29, 2001 (based on
the last sales price of $4.969 per share as reported on the NASDAQ Stock
Market).

         18,980,698 shares of the registrant's common stock were outstanding
as of March 30, 2001.

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<PAGE>

                            ESENJAY EXPLORATION, INC.
                        FOR YEAR ENDED DECEMBER 31, 2000

                                TABLE OF CONTENTS
                                   FORM 10-KSB

                                     PART I
<TABLE>
<CAPTION>
ITEM                                                                                 PAGE
<S>      <C>                                                                         <C>
1.       Description of Business....................................................    3

2.       Description of Property....................................................   17

3.       Legal Proceedings..........................................................   18

4.       Submission of Matters to a Vote of Security Holders........................   18

                                     PART II

5.       Market for Common Equity and Related Stockholder Matters...................   19

6.       Management's Discussion and Analysis.......................................   19

7.       Financial Statements.......................................................   29

8.       Changes in and Disagreements with Accountants on
           Accounting and Financial Disclosure......................................   46

                                    PART III

9.       Directors, Executive Officers, Promoters and Control Persons;
           Compliance with Section 16(a) of the Exchange Act........................   47

10.      Executive Compensation.....................................................   49

11.      Security Ownership of Certain Beneficial Owners
           and Management...........................................................   52

12.      Certain Relationships and Related Transactions.............................   54

                                     PART IV

13.      Exhibits and Reports on Form 8-K...........................................   56

         Signatures.................................................................   58
</TABLE>

                                       2
<PAGE>

                                     PART I

         This Form 10-KSB contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. The Company's actual results could differ
materially from those set forth in the forward-looking statements. Certain
factors that might cause such a difference are discussed in the introductory
paragraph to Management's Discussion and Analysis beginning on page 20 of
this Form 10-KSB.

ITEM 1.  DESCRIPTION OF BUSINESS

GENERAL

                                   THE COMPANY

         Esenjay Exploration, Inc. (the "Company") is an independent energy
company engaged in the exploration for and development of natural gas and
oil. The Company has assembled a diverse inventory of technology enhanced
natural gas and oil exploration projects located primarily along the Texas
and Louisiana Gulf Coast (the "Exploration Projects"). It should be noted
that the Company defines a "project" as a distinct 3-D seismic data set area
that often comprises multiple exploratory "prospects". The Company believes
that the Exploration Projects represent a diverse array of technology
enhanced, 3-D seismic evaluated, ready to drill natural gas exploration
projects that can expose the Company to major gas and oil reserve growth
opportunities for several years to come. In May of 1998 the Company acquired
an array of 28 exploration projects located along the Texas Gulf Coast from
Esenjay Petroleum Corporation ("EPC") and Aspect Resources LLC ("Aspect")
pursuant to an Acquisition Agreement and Plan of Exchange (as amended, the
"Acquisition Agreement"). At that time the Company's gas and oil properties
and projects included an inventory of unproven, undeveloped exploration
projects independently valued at over $64 million, coupled with only nominal
existing production. The Company's exploration plan is directed by a
comprehensive technical staff and the Company is managed by a group
experienced in geology, geophysics, engineering, land, finance and related
areas. The Exploration Projects also include the Company's interests in
projects acquired since consummation of the Acquisitions. It is an integral
portion of the Company's business to continually add to its Exploration
Project inventory new internally generated projects. Each of the Exploration
Projects differs in scope and character and consists of one or more types of
assets, such as 3-D seismic data, leasehold positions, lease options, working
interests in leases, royalty interests or other mineral rights. Industry
partners typically participate in the Exploration Projects by purchase of a
promoted interest from the Company. In September of 1999 the Company acquired
3DX Technologies Inc., pursuant to which acquisition it expanded its
ownership in certain of its Exploration Projects, added interests in other
projects, and expanded its technical staff. From 1998 through 2000 the
Company has significantly increased its gas and oil production and reserves
while continuing to add to its project inventory.

         OVERVIEW OF CURRENT ACTIVITIES AND RECENT EVENTS. Most of the
Exploration Projects have been enhanced with 3-D seismic data in conjunction
with computer aided exploration ("CAEX") technologies. The 3-D seismic data
acquired to date covers approximately 2,200 square miles, with additional 3-D
seismic surveys planned for 2001. A significant number of the Exploration
Projects have reached the drilling stage, and the Company has budgeted
approximately $26 million to fund its drilling, completion, land and seismic
activities in 2001. The budget is projected to fund the Company's net cost in
over 50 wells.

         Included in the 2001 budget is the Company's net cost in
approximately six planned delineation and/or development wells to be drilled
in conjunction with the two recent field discoveries. The discoveries were
the Grand Slam Field discovered by the Company's Runnells #3 well and the
Hordes Creek Field discovered by its Pereira Childrens Trust #2 well. The
Pereira Childrens Trust #2 well has been renamed the Hamman & Anderson #2
well. The Company believes that delineation of both fields, which are
operated by the Company, can add substantial new proven reserves to the
Company's gas and oil reserve base in 2001.

         The Company, which utilizes the successful efforts method of
accounting, entered 2001 having gone from nominal second quarter 1998 gas and
oil revenues of approximately $35,000 per month and large operating cash flow
deficits to a company with over $3,500,000 per month in oil and gas revenues
in the fourth quarter of 2000. Its revenue began to grow rapidly in the
second half of 1999 as wells drilled after closing of the transactions
pursuant to the

                                       3
<PAGE>

Acquisition Agreement began to rapidly come on line. Gas and oil production is
expected to continue to increase in 2001. Revenues in 2001 are expected to
exceed those in 2000. In addition, since December 31, 2000, the Company has
reset its long term credit facility with Deutsche Bank AG, New York Branch.
The facility included $20,341,782 outstanding at December 31, 2000 of which
$6,750,000 was classified as current portion of long term debt. The reset
total credit availability has been increased to $29,000,000. A summary of the
impact of the successful efforts accounting method as it relates to the
Acquisitions and a survey of the Company's history are set forth below.

         SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company
utilizes the successful efforts method of accounting. Under this method it
expenses its exploratory dry hole costs and the field acquisition costs of 3-D
seismic data as incurred. The undeveloped properties, which were acquired
pursuant to the Acquisitions, were comprised primarily of interests in
unproven 3-D seismic based projects, and were recorded in May of 1998 at an
independently estimated fair market value of $54.2 million as determined by
Cornerstone Ventures, L.P., a Houston, Texas based investment banking firm.
Pursuant to the successful efforts method of accounting, the Company is
amortizing such initial costs of unproved properties on a straight-line basis
over a period not to exceed forty-eight months, as well as recognizing
property specific impairments. As of December 31, 2000 the unamortized balance
was $5,334,700. In 2000 this amortization resulted in a $5,176,100 expense and
impairments totaled an additional $4,771,272. Impairments were primarily
related to unproved property costs on projects regarding which management
believes have diminished value based upon 2000 exploration activities. Hence
significant non-cash charges primarily related to the accounting treatment of
the Company's unproven properties have depressed reported earnings of the
Company and will likely continue to do so in 2001; however, the non-cash
charges will not affect cash flows provided by operating activities nor the
ultimate realized value of the Company's natural gas and oil properties. The
amortization of properties acquired pursuant to the Acquisitions will conclude
not later than May of 2002.

         As a result of the tax rules applicable to the Acquisitions, the
Company will likely not be able to fully use that portion of its existing net
operating loss carry forward attributable to periods prior to May of 1998 in
the future.

         OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH DECEMBER 31,
1998. Prior to May of 1998 the Company operated on a much smaller scale. A
negotiation process led to the Company entering into the Acquisition
Agreement among the Company, EPC and Aspect. This Acquisition Agreement
required approval of the shareholders of the Company. At a special meeting of
shareholders held on May 14, 1998 the shareholders approved the Acquisition
Agreement, a recapitalization of the Company pursuant to which each
outstanding share of common stock would convert into one-sixth (1/6) of a
share of new common stock (the "Reverse Split"), a plan and agreement of
merger pursuant to which the Company would reincorporate in the state of
Delaware and would change its name to Esenjay Exploration, Inc. (the
"Reincorporation"), and the election of seven directors. Immediately after
the shareholders meeting, the Company closed the transactions provided for in
the Acquisition Agreement, implemented the Reverse Split, and completed the
Reincorporation. The result of the foregoing is that the Company conveyed a
substantial majority of its Common Stock to acquire an array of significant
technology enhanced natural gas oriented exploration projects. The Company
believed the Acquisitions would facilitate expanded access to capital markets
due to the value and diversity of its exploration project portfolio. The
Company also believes the transactions significantly enhanced the Company's
management team.

         On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering
the Company had 15,762,723 shares outstanding.

         OVERVIEW OF 1999 ACTIVITIES. As a result of the above-described
acquisitions, restructuring, and the underwritten offering, the Company
believed it was, and believes it continues to be, positioned for a period of
significant exploration activity on its technology enhanced projects. Many of
the projects had reached the drilling stage. In many instances the requisite
process of geological and/or engineering analysis, followed by acreage
acquisition of leasehold rights and seismic permitting, and 3-D seismic field
data acquisition, then processing of the data and finally its interpretation,
required several years and the investment of significant capital. Management
believes the acquisition of projects at this advanced stage has not only
reduced the drilling risk, but also positioned the Company to consistently
drill on a broad array of exploration prospects for years to come.

         The Company ended 1999 having gone from nominal third quarter 1998
gas and oil revenues of

                                       4
<PAGE>

approximately $35,000 per month and large operating cash flow deficits to a
company which averaged $1,815,637 per month in net oil and gas revenues in
the fourth quarter of 1999. The increasing revenue allowed the Company to
achieve positive operating cash flow (before capital expenditures, and before
the costs of acquisition of new 3-D seismic data, and changes in working
capital) in the third quarter, which operating cash flow increased in the
fourth quarter.

         On May 12, 1999, the Company announced that it had entered into a
Plan and Agreement of Merger with 3DX Technologies, Inc. ("3DX") which
provided for the merger of 3DX into the Company. The shareholders of both
companies approved the transaction at their respective meetings on September
23, 1999 and the merger was consummated the same day. The terms of the merger
provided for 3DX shareholders to receive, at their election, either (i) the
issuance of one share of Esenjay common stock for 3.25 shares of 3DX common
stock; or (ii) the issuance of a new Esenjay convertible preferred stock at a
ratio of one share of Esenjay convertible preferred stock for each 2.75 shares
of 3DX common stock. The preferred stock did not require payment of dividends.
Approximately 91% of the 3DX common shares converted into Esenjay common stock
and approximately 9% were converted into Esenjay convertible preferred stock.
As a result, Esenjay issued approximately 2,906,800 new shares of common stock
and 356,999 shares of convertible preferred stock. The convertible preferred
stock was redeemable at Esenjay's sole option until September 23, 2000 at
$1.925 per share. It was subsequently redeemed in September of 2000.

         OVERVIEW OF 2000 ACTIVITIES. In 2000 the Company utilized its
increased cash resources to increase its capital expenditures to
approximately $25 million. The increased available capital allowed the
Company to focus drilling on higher risk, higher potential opportunities.
This risk profile led to the drilling of the Company's Runnells #3 discovery
well located in the Duncan Slough project area in the fourth quarter of 2000
and its Pereira Children's Trust #2 well located in the Hordes Creek project
area that was logged and completed in the first quarter of 2001. The Pereira
Childrens Trust #2 well has subsequently been renamed the Hamman & Anderson
#2 well. Both discoveries will be the focus of significant capital investment
in 2001 as field delineation wells are drilled.

         In 2000 the Company participated in a total of 52 new wells that
reached total depth and were logged during the year. Of the total wells
drilled and logged during 2000, 29 were completed as of March 31, 2001, two
are scheduled to commence production upon completion and pipeline
connections, and 21 were dry holes.

         The Company added 19.256 billion cubic feet equivalent ("BCFE") of
new gas and oil reserves from its 2000 drilling activities. The added
reserves do not reflect the full potential of the Grand Slam Field
anticipated to be ascertained through the delineation wells to be drilled in
2001, nor does it reflect any reserves attributable to the Hordes Creek Field
which was not discovered until the first quarter of 2001. Year end 2000
reserves were adversely affected by 6.241 BCFE of downward adjustments in
prior discoveries primarily related to wells located in the Hackberry trend.
The Hackberry wells were previously believed by Company engineers and by the
Company's independent reservoir engineers to be primarily depletion drive
reservoirs but actual results showed a stronger water drive component that
shortened the wells' lives and led to the downward adjustments. These
adjustments are incorporated in the December 31, 2000 gas and oil reserve
studies. Year end totals were also affected by the sale of 3.398 BCFE
pursuant to a transaction with an industry partner closed in early 2000.

         On September 23, 2000, the Company redeemed all of its previously
outstanding preferred stock. The redemption was pursuant to a unilateral
right to redeem in favor of the Company. A total of 356,999 shares of
preferred stock were redeemed at the contractual redemption price of $1.925
per share.

         On October 12, 2000 the Company finalized and closed an agreement
with 420 Energy Investments, Inc. ("420") pursuant to which $864,000 in
non-recourse debt and $562,034 in interest on non-recourse debt was satisfied.
Consideration paid to 420 was $300,000 in cash, plus an agreement to drill one
well in the project area, plus an agreement to pay to 420 cash payments on the
date drilling may commence on any future wells it may drill on one exploration
project area located in Terrebonne Parish, Louisiana. Any such future payments
would range from $20,000 per well to $100,000 per well, but would never exceed
a total of $300,000. In addition, 420 retained its prior right to an
overriding royalty equal to 2% of the Company's interest in any well drilled
in the project area in Terrebonne Parish. As a result of the transaction, the
Company recognized an extraordinary gain in the fourth quarter of 2000 of
$1,126,034. The initial well in which the Company participated was drilled in
the fourth quarter. It elected to not participate in completion of the well
due to what the Company believed were marginal expected economics. The Company
has no obligation or any current plans to drill any future wells on the
project acreage.

                                       5
<PAGE>

         On October 2, 2000 the Company announced it had retained Deutsche
Bank Securities, Inc. to advise it concerning various strategic alternatives
intended to better maximize shareholder value. It also retained the firm of
Randall & Dewey, Inc. to initiate and manage a transaction to seek to better
realize this value through various alternatives such as selling the Company
for cash, merger, stock trade or acquisition. Since the Company's recent
field discoveries, the Company has determined that it can better maximize
shareholder value by drilling delineation wells near the discoveries and
executing its overall exploratory drilling plan. Accordingly, it has
announced that it does not plan to actively pursue new alternatives for a
potential sale of the Company.

         OVERVIEW OF 2001 ACTIVITIES. The Company believes it entered 2001 in
a position to continue to expand its production and reserves via exploration
activities on its technology-enhanced projects. By utilizing the increased
capital available to it from operating cash flow, financings and industry
partner transactions, the Company intends to pursue an aggressive exploration
budget in its major trends of activity. The Company's net daily production
approximated 364 barrels of oil per day and 16,681 Mcf natural gas per day in
March of 2001. Subsequent to December 31, 2000, the Company reset its credit
facility with Deutsche Bank AG, New York Branch. Availability pursuant to the
facility was increased to $29 million with a borrowing base adjustment
scheduled for the end of the second quarter of 2001. The facility is divided
into two tranches. Tranche A is a revolving credit facility with $20 million
available of which $14.84 million was outstanding on March 29, 2001. No
principal amortization is required on Tranche A in 2001. Tranche B is a $9
million loan that amortizes in four equal principal payments beginning April
30, 2001. As a result of its current operating cash flow combined with
available credit and the proceeds of anticipated sales of select Exploration
Project interests to industry partners, the Company believes it is positioned
to fund its 2001 drilling and exploration activities, the results of which
are intended to continue the upward trends of increasing cash flow and
reserves. The Company will look to a variety of sources in addition to
operating cash flow to further supplement its capital expenditures budget,
including its credit facilities and sales of additional promoted project
interests to industry partners, as it seeks to maximize its interests and
manage its risks while aggressively pursuing its exploration projects.

         The Company has budgeted $26 million in drilling, completion, land
and seismic expenditures on interests in over 50 wells in 2001. Through this
exploration program, the Company believes it can continue its trends of
growth in net production, net revenues, operating cash flow, and net gas and
oil reserves throughout the year 2001 and beyond. Its 2001 drilling activity
will primarily be divided between a continuation of exploratory drilling on
high potential target features, which drilling will be coupled with the field
delineation and development drilling associated with the Company's recent
field discoveries. An array of lower risk prospects will also be drilled, the
cost of which will be a modest portion of the capital budget.

         As of March 30, 2001, the Company has 18,980,698 total shares of
common stock outstanding. It employs thirty-four full time employees,
including five in its exploration and geophysical departments, seven in its
operations department, two in its exploitation department, and seven in its
land department. Its focus continues to be the implementation of its business
strategy as set forth in this section.

STRATEGY

         The Company's strategy is to expand its reserves, production and
cash flow through the implementation of an exploration program that is
oriented toward (i) obtaining dominant positions in core areas of
exploration; (ii) enhancing the value of the Exploration Projects and
reducing exploration risks through the use of 3-D seismic and CAEX
technologies; (iii) maintaining an experienced technical staff with the
expertise necessary to take advantage of the Company's proprietary 3-D
seismic and CAEX seismic data; (iv) reducing exploration risks by
identification of potential moderate-depth gas reservoirs, which the Company
believes are conducive to hydrocarbon detection technologies; and (v)
retaining operational control over critical exploration decisions.

         OBTAIN DOMINANT POSITION IN CORE AREAS. The Company has identified core
         areas for exploration along the Texas and Louisiana Gulf Coasts that
         have geological trends with demonstrated histories of prolific natural
         gas production from reservoirs high in porosity and permeability with
         profiles suitable for seismic evaluation. Unlike the Gulf of Mexico,
         where 3-D seismic data typically is owned and licensed by many
         companies that compete intensely for leases, the private right of
         ownership of onshore mineral rights enables individual exploration
         companies to proprietarily control the seismic data within focused core

                                       6
<PAGE>

         areas. The Company believes that by obtaining substantial amounts of
         proprietary 3-D seismic data and significant acreage positions within
         its core areas, it will be able to achieve a dominant position in
         focused portions of those areas. With such a dominant position, the
         Company believes it can better control the core areas' exploration
         opportunities and future production, and can attempt to minimize costs
         through economies of scale and other efficiencies inherent in its
         focused approach. Such cost savings and efficiencies include the
         ability to use the Company's proprietary data to reduce exploration
         risks and lower its leasehold acquisition costs by identifying and
         purchasing leasehold interests only in those focused areas in which the
         Company believes exploratory drilling is most likely to be successful.

         USE OF 3-D SEISMIC AND CAEX TECHNOLOGIES. The Company attempts to
         enhance the value of its Exploratory Projects through the use of 3-D
         seismic and CAEX technologies, with an emphasis on direct hydrocarbon
         detection technologies. These technologies create computer generated
         3-dimensional displays of subsurface geological formations that enable
         the Company's explorationists to more accurately map structural
         features to detect seismic anomalies that are not apparent in 2-D
         seismic surveys. The Company believes that 3-D seismic technology, if
         properly used, will reduce drilling risks and costs by reducing the
         number of dry holes, optimizing well locations and reducing the number
         of wells required to exploit a discovery. The Company believes that 3-D
         seismic surveys are particularly suited to its Exploration Projects
         along the Texas and Louisiana Gulf Coasts.

         EXPERIENCED TECHNOLOGICAL TEAM. The Company maintains an experienced
         technical staff, including engineers, geologists, geophysicists,
         landmen and other technical personnel. After the Acquisitions, the
         Company hired most of EPC's technical personnel, who, in some
         instances, had worked together for over 15 years. It further expanded
         its technical staff when it acquired 3DX in September of 1999. In
         addition, the Company has agreements with various geotechnical services
         consultants who provide the Company geophysical expertise in managing
         the design, acquisition, processing and interpretation of 3-D seismic
         data in conjunction with CAEX data.

         FOCUSED DRILLING OBJECTIVES. In addition to using 3-D seismic and CAEX
         technologies, the Company often seeks to reduce exploration risks by
         exploring at moderate depths that are deep enough to discover sizable
         gas accumulations (generally 8,000 to 12,500 feet) and that also are
         conducive to direct hydrocarbon detection, but not so deep as to be
         highly exposed to the greater mechanical risks and drilling costs
         incurred in the deep plays in the region. In conjunction with
         interpreting the 3-D seismic and CAEX data relating to the Company's
         moderate depth wells, the Company is also pursuing potential prospects
         in deep gas provinces in which 3-D seismic and CAEX technologies are
         used to identify a structural image of the subsurface. Generally,
         reservoirs at deeper depths are not conducive to direct hydrocarbon
         detection but have potential for the discovery of greater quantities of
         hydrocarbons.

         CONTROL OF EXPLORATION AND OPERATIONAL FUNCTIONS. The Company believes
         that having control of the most critical functions in the exploration
         process will enhance its ability to successfully develop its
         Exploration Projects. The Company has a controlling interest in many of
         the Exploration Projects, including proprietary interests in most of
         the 3-D seismic data relating to those projects. As a result, the
         Company will often be able to influence the areas to explore, manage
         the land permitting and option process, determine seismic survey areas,
         oversee data acquisition and processing, prepare, integrate and
         interpret the data and identify each prospect drillsite. In addition,
         the Company will likely be the operator of a majority of the wells
         drilled within the Exploration Projects.

EXPLORATION PROJECTS

         Most of the Exploration Projects are concentrated within the Frio,
Wilcox, Texas Hackberry and Yegua core project areas. The Frio core area
generally is in the middle Texas Gulf Coast where the Company believes Frio
targets exist at moderate to deeper depths. The Wilcox core area generally is
in the middle Texas Gulf Coast in an area the Company believes to have
prospects for Wilcox sand exploration. The Texas Hackberry core area is
located in Jefferson and Orange Counties, Texas, in an area which the Company
believes offers drilling opportunities in the Hackberry formations, as well
as Miocene and deeper Vicksburg sands. The Yegua trend extends from San
Patricio County in Texas through Beauregard and Calcasieu Parishes in
Louisiana. The Company became active in two

                                       7
<PAGE>

portions of this trend in 1999. Other Exploration Projects include projects
in Louisiana and Mississippi that either are in early stage exploration areas
that may develop into new core project areas, or non-core area projects,
which are projects that are not presently expected to be further expanded.

         Each of the Exploration Projects differs in scope and character and
consists of one or more types of assets, such as 3-D seismic data, leasehold
positions, lease options, working interests in leases, royalty interests or
other mineral rights. The Company's percentage interest in each Exploration
Project (a "Project Interest") represents the portion of the interest in the
Exploration Project it shares with its other project partners. Because each
Exploration Project consists of a bundle of assets which may or may not
include a working interest in the project, the Company's Project Interest
simply represents the Company's proportional ownership in the bundle of
assets that constitute the Exploration Project. Therefore, the Company's
Project Interest in an Exploration Project should not be confused with the
working interest that the Company will own when a given well is drilled. It
is possible that while the Company may own a 50.0% Project Interest, it may
only be entitled to 25.0% of the working interest involved in the Exploration
Project. Each Exploration Project represents a negotiated transaction between
the project partners. The Company's working interest may be higher or lower
than its Project Interest.

         The following table sets forth certain information about each of the
Exploration Projects:

<TABLE>
<CAPTION>
                                               EXPLORATION PROJECTS

                                               ACRES LEASED OR UNDER OPTION AT              SQUARE MILES OF
                                                      MARCH 27, 2001(1)                    3-D SEISMIC DATA
                                           PROJECT         PROJECT          COMPANY           RELATING TO            PROJECT
PROJECT AREAS                               GROSS            NET              NET            PROJECT AREA          INTEREST(2)
-------------------------------------    ------------    -------------    ------------    --------------------    --------------
<S>                                      <C>             <C>              <C>             <C>                     <C>
SOUTH TEXAS
FRIO CORE AREA
    Allen Dome...................             730.05          424.37           384.58              53                  90.62%
    Lafite.......................           4,792.60        4,672.15         4,432.17              53                  94.86%
    Gillock......................          16,054.65       13,293.09         4,933.91              70                  37.12%
    Blessing.....................              80.00           80.00            27.14              22                  33.93%
    Tidehaven....................           2,536.68        2,034.23         1,060.40              28                  52.13%
    El Maton.....................           4,080.47        3,257.79         2,120.19              29                  65.08%
    Midfield.....................           1,978.40        1,097.85           952.13              21                  86.73%
    Markham......................           2,126.24        2,126.24           718.37               5                  33.79%
    Buckeye Ranch................           2,898.74        1,861.73           837.65              40                  44.99%
    Duncan Slough................           4,902.54        3,643.61         1,638.08              25                  44.96%
    SW Pheasant (Francitas)......           1,102.95          732.99           549.72              10                  75.00%
    La Rosa......................              80.00           80.00             7.60              25                   9.50%
    Vicksburg Area II Phase I....           3,522.02        3,410.68         1,446.46              76                  42.41%
    Vicksburg Area II Phase II...           1,126.63        1,126.63           473.18              50                  42.00%
    Wolf Point...................             632.00          632.00           174.75               8                  27.65%
    Archie.......................             489.40          489.40            88.71              14                  18.13%
    Powerhorn/Matagorda Bay......             480.00          480.00            72.00              30                  15.00%
    Raymondville.................          12,412.19       12,345.04         6,920.30              62                  56.06%
    Smith Point..................               ---             ---              ---               80                   7.50%
                                         ------------    -------------    ------------    --------------------
                      Frio Sub-Total       60,025.56       51,787.80        26,837.34             701
WILCOX CORE AREA
    Gila Bend....................             531.84          531.84            78.22              16                  14.71%
    Hall Ranch...................           8,412.92        7,618.18         3,001.80              57                  39.40%
    Hordes Creek.................           4,889.58        4,842.91         2,043.00              25                  42.19%
    Mikeska W....................           5,540.49        5,256.85         1,974.79              32                  37.57%
    Hagist Ranch N E.............           1,979.59        1,979.60         1,781.62              10                  90.00%
    Verdad.......................           4,918.53        4,671.85         1,191.10              40                  25.50%
    Orangedale West..............           2,314.33        2,207.81         1,980.24              10                  89.69%
    Riverdale....................           7,351.71        7,059.41         1,764.87              23                  25.00%
                                         ------------    -------------    ------------    --------------------
                    Wilcox Sub-Total       35,938.99       34,168.45        13,815.64             213
TEXAS HACKBERRY CORE AREA
    Lox B                                   4,345.05        2,091.14           504.57              62                  24.99%
    West Port Acres..............             728.95          650.55            81.32              21                  12.50%

                                       8
<PAGE>

<CAPTION>
                                               EXPLORATION PROJECTS

                                               ACRES LEASED OR UNDER OPTION AT              SQUARE MILES OF
                                                      MARCH 27, 2001(1)                    3-D SEISMIC DATA
                                           PROJECT         PROJECT          COMPANY           RELATING TO            PROJECT
PROJECT AREAS                               GROSS            NET              NET            PROJECT AREA          INTEREST(2)
-------------------------------------    ------------    -------------    ------------    --------------------    --------------
<S>                                      <C>             <C>              <C>             <C>                     <C>
    Stowell/Big Hill.............           1,462.00          943.46           103.51              56                  10.97%
    Cheek                                  11,367.85        8,305.05         1,116.90              48                  13.45%
    Lovell Lake..................          11,687.91        9,559.19         1,594.55              65                  16.68%
    West Beaumont................           1,071.91          850.80            62.73              23                   7.37%
                                         ------------    -------------    ------------    --------------------
           Texas Hackberry Sub-Total       30,663.67       22,400.19         3,463.58             275
YEGUA CORE AREA
    Papalote.....................          36,562.00       35,332.76        18,654.18              98                  52.80%
    Inez.........................             202.51          199.26            68.20              10                  34.23%
    West Inez....................              56.67           56.67            56.67              10                 100.00%
    Mathis.......................             924.55          924.55           508.51              40                  55.00%
    TBC  ........................          44,695.00       37,214.00        14,888.00              90                  40.00%
    South Louisiana Eocene.......           6,271.41        6,191.94         1,601.30              85                  25.86%
    Howards Creek................          33,409.93       33,362.26         7,292.82              85                  21.86%
                                         ------------    -------------    ------------    --------------------
                     Yegua Sub-Total      122,122.07      113,281.44        43,069.68             418
OTHER LOUISIANA
    Four Isle Dome                                                                                 80                   7.50%
    Starboard Lapeyrouse.........           3,893.68        2,739.15           693.79              35                  25.33%
                                         ------------    -------------    ------------    --------------------
                 Louisiana Sub-Total        3,893.68        2,739.15           693.79             115
OTHER TEXAS
    East Texas Pinnacle Reef(3)..            TBD              TBD              TBD                400                 TBD
                                         ------------    -------------    ------------    --------------------
               Other Texas Sub-Total         TBD              TBD              TBD                400
MISSISSIPPI
    Thompson Creek...............             798.15          696.73           657.05              12                  94.30%
    Melvin.......................             275.16          255.18            58.80              64                  23.04%
                                         ------------    -------------    ------------    --------------------
               Mississippi Sub-Total        1,073.31          951.91           715.85              76
                                         ------------    -------------    ------------    --------------------

                  TOTAL ALL PROJECTS      253,717.28      225,328.94        88,595.88           2,198
                                         ============    =============    ============    ====================
</TABLE>

------------
(1)      Project Gross acres refers to the number of acres within a project.
         Project Net acres refers to leaseable acreage by tract. Company Net
         acres are either leased or under option in which the Company owns an
         undivided interest. Company Net acres were determined by multiplying
         the project net acres leased or under option times the Company's
         working interest therein.
(2)      Each of the Exploration Projects differs in scope and character and
         consists of one or more types of assets, such as 3-D seismic data,
         leasehold positions, lease options, working interests in leases,
         royalty interests or other mineral rights. The Company's percentage
         interest in each Exploration Project (a "Project Interest") represents
         the portion of the interest in the Exploration Project it shares with
         its other project partners. Because each Exploration Project consists
         of a bundle of assets which may or may not include a working interest
         in the project, the Company's Project Interest simply represents the
         Company's proportional ownership in the bundle of assets that
         constitute the Exploration Project. Therefore, the Company's Project
         Interest in an Exploration Project should not be confused with the
         working interest that the Company will own when a given well is
         drilled. It is possible that while the Company may own a 50.0% Project
         Interest, it may only be entitled to 25.0% of the working interest
         involved in the Exploration Project. Each Exploration Project
         represents a negotiated transaction between the project partners. The
         Company's working interest may be higher or lower than its Project
         Interest.
(3)      Consists of approximately 400 square miles of 3-D seismic data to which
         Aspect has rights pursuant to a license agreement, and to which the
         Company may acquire an interest pursuant to a geophysical technical
         services agreement with Aspect.

EXPLORATION PROJECT AREA DESCRIPTIONS.

         The Company is focused on certain core project areas along the Texas
and Louisiana Gulf Coast where it has pursued a trend strategy. Focusing on
trends, as opposed to individual projects, allows the Company the opportunity to
gain and exploit regional knowledge, develop competitive advantages and provide
expansion room once concepts are proven.

                                       9
<PAGE>

The Company's four core trend areas are characterized by high reservoir
quality, an extensive knowledge base due to technical staff experience and
focus, and geophysical characteristics suitable to 3-D seismic imaging. The
four core trend areas are further described below:

         FRIO CORE AREA. In the Frio Trend, the Company has interests in 19
3-D seismic surveys that cover approximately 700 square miles. It plans to
drill and/or participate in approximately 40 wells in the Frio Trend in 2001.
This trend extends across the Texas Gulf Coast from the Houston area to the
border of Mexico. Esenjay has numerous projects and prospects scattered
throughout this large trend and has significantly increased its planned
capital expenditures in the trend as compared with 2000.

          WILCOX CORE AREA. In the Wilcox Trend, the Company has nine 3-D
seismic surveys covering approximately 213 square miles. It plans to drill
approximately 10 wells in the Wilcox Trend in 2001. This trend extends
through Texas from Louisiana to Mexico. Production from the Wilcox ranges
from the very shallow to over 16,000 feet in depth. The Company's focus is on
certain of the portions of the Wilcox Trend generally located below 10,000
feet. These deeper portions have historically had less total drilling and
allow the Company ample room to expand its activities should success in 2001
and beyond so warrant. It has significantly increased its 2001 capital budget
(as compared to 2000) in this area which it believes to represent exceptional
upside potential.

          TEXAS HACKBERRY CORE AREA. The Texas Hackberry Trend, sometimes
referred to as the Hackberry Embayment, is an area in which the Company has
interests in six 3-D seismic surveys covering approximately 275 square miles.
It plans to drill at least seven wells in the Hackberry Trend in 2001. Based
on its experience and the experience of certain of its affiliates, the
Company believes that the portions of the Hackberry formation in geographical
proximity to the Gulf of Mexico and the Texas/Louisiana border have proven to
be an excellent area for the use of 3-D seismic data. Historical drilling in
the Hackberry Sands had exhibited low historical success rates that have been
greatly improved in the Company's experience in projects in which it has
participated in the Hackberry through the use of 3-D seismic data. The
Company has drilled 21 successful wells out of 29 attempts utilizing modern
3-D seismic data. Included in the seismic evaluation of the Texas Hackberry
Trend has been significantly use of direct hydrocarbon detection technologies.

          YEGUA CORE AREA. In the Yegua Trend, the Company currently has
interests in six 3-D seismic surveys. The Company will own interests in an
aggregate of approximately 418 square miles of 3-D seismic data in the trend
in 2001. The Company expects to drill approximately six wells in the Yegua
Trend in 2001. This trend extends from Beauregard Parish, Louisiana, to San
Patricio County, Texas, and is generally characterized by structural and
stratigraphically trapped hydrocarbons that may appear on 3-D seismic data as
seismic anomalies. The Company believes that the area is comprised of
physical characteristic such that it will be well situated for direct
hydrocarbon detection technologies.

CAEX TECHNOLOGY AND 3-D SEISMIC

         The Company, either directly or through its partners, uses CAEX
technology to collect and analyze geological, geophysical, engineering,
production and other data obtained about potential gas or oil prospects. The
Company uses this technology to correlate density and sonic characteristics
of subsurface formations obtained from 2-D seismic surveys with like data
from similar properties, and uses computer programs and modeling techniques
to determine the likely geological composition of a prospect and potential
locations of hydrocarbons.

         Once all available data has been analyzed to determine the areas
with the highest potential within a prospect area, the Company may conduct
3-D seismic surveys to enhance and verify the geological interpretation of
the structure, including its location and potential size. The 3-D seismic
process produces a three-dimensional image based upon seismic data obtained
from multiple horizontal and vertical points within a geological formation.
The calculations needed to process such data are made possible by computer
programs and advanced computer hardware.

         While large oil companies have used 3-D seismic and CAEX
technologies for over 20 years, these methods were not affordable by smaller,
independent gas and oil companies until more recently, when improved data

                                       10
<PAGE>

acquisition equipment and techniques and computer technology became available
at reduced costs. The Company is using these technologies on a continuing
basis. The Company believes its use of CAEX and 3-D seismic technology may
provide it with certain advantages in the exploration process over those
companies that do not use this technology. These advantages include better
delineation of the subsurface, which can reduce exploration risks and help
optimize well locations in productive reservoirs. The Company believes these
advantages can be readily validated based upon general industry experience as
well as its own results in 1999 and 2000. Because computer modeling generally
provides clearer and more accurate projected images of geological formations,
the Company believes it is better able to identify potential locations of
hydrocarbon accumulations and the desirable locations for wellbores.

EXPLORATION AND DEVELOPMENT

         The Company considers the Gulf Coast to be the premier area in the
United States to explore for significant new reserves. This conclusion is
based on several characteristics including (i) a large number of productive
intervals throughout a significant sedimentary section, (ii) numerous wells
with which to calibrate 3-D seismic data and (iii) complicated geological
formations that the Company believes 3-D seismic technology is particularly
well suited to interpretation. Upon completion of the Acquisitions, the
Company spread its focus over an array of exploration projects along the Gulf
Coast and intends to expand its project inventory in these areas. The
Company's Exploration Project inventory is primarily along the Gulf Coast of
Texas and Louisiana. The focus is on natural gas exploration prospects with a
numerical concentration along the Texas Gulf Coast, many of which were
delineated by seismic hydrocarbon indicators. Additional 2-D and 3-D seismic
surveys may be required to evaluate these areas more fully, and when
determined appropriate, the Company intends to acquire acreage and drill
wells as indicated by the evaluations.

         The Company intends to drill prospects where the formations being
tested are known to be productive in the general area and where it believes
3-D seismic can be used to increase resolution and thereby reduce risk. The
extent to which the Company will pursue its activities in the onshore Gulf
Coast region will be determined by the availability of the Company's
resources and the availability of joint venture partners.

ACQUISITIONS AND DIVESTMENTS

         The Company has de-emphasized producing property acquisition
activities. The Company intends to limit its near term producing property
acquisitions to opportunities that facilitate its exploration activities. The
Company may readdress this approach if it identifies an opportunity it
believes to be of exceptional benefit to its shareholders or as changing
market conditions may warrant.

HEDGING ACTIVITIES AND MARKETING

         The Company markets its natural gas through monthly spot sales.
Because sales made under spot sales contracts result in fluctuating revenues
to the Company depending upon the market price of gas, the Company may enter
into various hedging agreements to minimize the fluctuations and the effect
of price declines or swings. In February of 2000, in conjunction with its
financing with Deutsche Bank, the Company established natural gas hedges with
an affiliate of Deutsche Bank. Pursuant to these hedges, the Company then had
9,381 MMBtu/day of net production hedged for the first quarter of 2000, 9,031
MMBtu/day hedged for the second quarter of 2000, 8,646 MMBtu/day for the
third quarter of 2000, 8,278 MMBtu/day for the fourth quarter of 2000, 7,161
MMBtu/day for the first quarter of 2001, 6,880 MMBtu/day for the second
quarter of 2001, 6,600 MMBtu/day for the third quarter of 2001, and 6,319
MMBtu/day for the fourth quarter of 2001. All hedges were at $2.45 per MMBtu.
These hedges were restructured in January of 2001 for all periods beginning
February 1, 2001, and any rights or obligations of the Company pursuant to
the previously existing $2.45 hedges were cancelled. Pursuant to the
restructured agreements, the Company has subjected volumes of its Gulf Coast
natural gas production to a "collar" structure with a floor price of $3.25
per MMBtu and a ceiling or cap price of $4.00 per MMBtu. Volumes committed to
this structure are 7,500 MMBtu per day in February and March of 2001, 7,900
MMBtu per day in the second quarter of 2001, and 8,000 MMBtu per day in the
third and fourth quarter of 2001. In 2002, volumes committed are 8,500,
8,000, 7,500 and 7,000 MMBtu per day in the first through fourth quarters
respectively. Finally, volumes committed to the collar structure include
4,500 MMBtu per day for calendar year 2003.

                                       11
<PAGE>

         In the third quarter of 2000 the Company hedged an additional 5,000
MMBtu/day of natural gas. The hedge prices were at $4.70 per MMBtu for the
months of September through December 2000, and at $4.01 per MMBtu for the
months of January through December 2001. These hedges were not restructured
and also remain in effect.

         In September of 1999, the Company entered into a "collar" hedge
arrangement on certain of its oil production. It entered into an oil hedge
for a quantity equal to 300 barrels of oil per day in the fourth quarter of
1999, 280 barrels of oil per day in the first quarter of 2000, 256 barrels of
oil per day in the second quarter of 2000, and 237 barrels of oil per day in
the third quarter of 2000, all of which transactions were structured with an
$18.00 floor price and a $20.40 cap price. These positions were supplemented
with oil hedges for 238 barrels of oil per day in the fourth quarter of 2000,
and 175 barrels of oil per day, 168 barrels of oil per day, 161 barrels of
oil per day and 154 barrels of oil per day for the first through fourth
quarters of 2001, respectively, all of which supplemental hedges were at
$21.03 per barrel. These hedges also remain in effect.

         As a result of the above-referenced transactions, the Company has
hedged varying quantities of its natural gas through December of 2003 and
varying quantities of its oil production through December of 2001. First
quarter 2001 hedges are estimated to approximate 76.6% of the Company's
natural gas production and 50.5% of its oil production for such quarter.
Future percentages will vary.

         All of the Company's natural gas and oil production is now sold
under market-sensitive or spot price contracts. The Company's revenues from
natural gas and oil sales fluctuate depending upon the market price of
natural gas or oil. In 1999, purchasers accounting for more than 10% of the
Company's total revenue were Coral Energy Resources, L.P., Pan Energy
Marketing Company, Duke Energy Trading & Marketing and Duke Energy Field
Services, Inc. In 2000, purchasers accounting for more than 10% of the
Company's total revenue were Duke Energy Transportation and Trading, Gulf
Energy Marketing, LLC and PG&E Texas Industrial Energy. The Company does not
believe the loss of any existing purchaser would have a material adverse
effect on the Company.

         The Company previously had a credit facility with Duke Energy
Financial Services, Inc. ("Duke"), pursuant to which an ongoing agreement was
established which still allows affiliates of Duke the right to gather,
process, transport and market, at competitive market rates, natural gas
produced from a majority of the Exploration Projects through December 31,
2005.

         The Company expects that its daily production will continue to
increase and it will periodically consider additional hedge transactions
consistent with its ongoing policy. Its policy is to periodically review its
projected natural gas and oil production from proved developed properties in
light of then current market conditions. Its objective is to seek a balance
pursuant to which it can prudently stabilize its future cash flows from
proven producing properties while providing ongoing upside potential should
product prices increase. It believes that as it continues to expand its
drilling budget this methodology allows it to have more control over its
short-term cash flow while not giving up the upside potential in its future
revenues, a substantial portion of which it projects to be from properties
within its project inventory which are yet to be drilled.

OPERATING HAZARDS AND INSURANCE

         The gas and oil business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations, and environmental hazards such as oil spills, gas
leaks, ruptures or discharges of toxic gases, the occurrence of any of which
could result in substantial losses to the Company due to injury or loss of
life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, cleanup responsibilities,
regulatory investigation and penalties and suspension of operations.

         The Company maintains a gas and oil lease operator insurance policy
that insures the Company against certain sudden and accidental risks
associated with drilling, completing and operating its wells. There can be no
assurance that this insurance will be adequate to cover any losses or
exposure to liability. The Company also carries comprehensive general
liability policies and an umbrella policy. The Company and its subsidiaries
carry workers'

                                       12
<PAGE>

compensation insurance in all states in which they operate. The Company
maintains various bonds as required by state and federal regulatory
authorities. Although the Company believes these policies provide coverage in
scope and in amounts customary in the industry, they do not provide complete
coverage against all operating risks. An uninsured or partially insured
claim, if successful and of sufficient magnitude, could have a material
adverse effect on the Company and its financial condition. If the Company
experiences significant claims or losses, the Company's insurance premiums
could be increased which may adversely affect the Company and its financial
condition or limit the ability of the Company to obtain coverage. Any
difficulty in obtaining coverage may impair the Company's ability to engage
in its business activities.

REGULATION

         GENERAL. The oil and gas industry is extensively regulated by
federal, state and local authorities. In particular, gas and oil production
operations and economics are affected by price controls, environmental
protection statutes, tax statutes and other laws and regulations relating to
the petroleum industry, as well as changes in such laws, changing
administrative regulations and the interpretations and application of such
laws, rules and regulations. Gas and oil industry legislation and agency
regulations are under constant review for amendment and expansion for a
variety of political, economic and other reasons. Numerous regulatory
authorities, federal, and state and local governments issue rules and
regulations binding on the gas and oil industry, some of which carry
substantial penalties for failure to comply. The regulatory burden on the gas
and oil industry increases the Company's cost of doing business and,
consequently, affects its profitability. The Company believes it is in
compliance with all federal, state and local laws, regulations and orders
applicable to the Company and its properties and operations, the violation of
which would have a material adverse effect on the Company or its financial
condition.

         EXPLORATION AND PRODUCTION. The Company's operations are subject to
various regulations at the federal, state and local levels. Such regulations
include (i) requiring permits for the drilling of wells; (ii) maintaining
bonding requirements to drill or operate wells; and (iii) regulating the
location of wells, the method of drilling and casing wells, the surface use
and restoration of properties upon which wells are drilled, the plugging and
abandoning of wells and the disposal of fluids used in connection with well
operations. The Company's operations also are subject to various conservation
regulations. These include the regulation of the size of drilling and spacing
units, the density of wells that may be drilled, and the utilization or
pooling of gas and oil properties. In addition, state conservation laws
establish maximum rates of production from gas and oil wells, generally
prohibiting the venting or flaring of gas, and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amount of gas and oil the Company can produce from its wells and to
limit the number of wells or the locations at which the Company can drill.

FEDERAL REGULATIONS

         SALES AND TRANSPORTATION OF NATURAL GAS. Historically, the
transportation and sales for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the
Natural Gas Policy Act of 1978 ("NGPA") and Federal Energy Regulatory
Commission ("FERC") regulations. Effective January 1, 1993, the Natural Gas
Wellhead Decontrol Act deregulated price for all "first sales" of natural
gas. Thus, all sales of gas by the Company may be made at market prices,
subject to applicable contract provisions. Sales of natural gas are affected
by the availability, terms and cost of pipeline transportation. Since 1985,
the FERC has implemented regulations intended to make natural gas
transportation more accessible to gas buyers and sellers on an open-access,
non-discriminatory basis.

         Beginning in April 1992, the FERC issued Order No. 636 and a series
of related orders, which required interstate pipelines to provide open-access
transportation on a not unduly discriminatory basis for all natural gas
shippers. The FERC has stated that it intends for Order No. 636 and its
future restructuring activities 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.
However, some appeals remain pending and the FERC continues to review and
modify its regulations regarding the transportation of natural gas. For
example, the FERC issued Order No. 637

                                       13
<PAGE>

which:

         o        lifts the cost-based cap on pipeline transportation rates in
                  the capacity release market until September 30, 2002, for
                  short-term releases of pipeline capacity of less than one
                  year,

         o        permits pipelines to file for authority to charge different
                  maximum cost-based rates for peak and off-peak periods,

         o        encourages, but does not mandate, auctions for pipeline
                  capacity,

         o        requires pipelines to implement imbalance management services,

         o        restricts the ability of pipelines to impose penalties for
                  imbalances, overruns and non-compliance with operational flow
                  orders, and

         o        implements a number of new pipeline reporting requirements.

         Order No. 637 also requires the FERC staff to analyze whether the
FERC should implement additional fundamental policy changes. These include
whether to pursue performance-based or other non-cost based ratemaking
techniques and whether the FERC should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid.

         In April 1999 the FERC issued Order No. 603, which implemented new
regulations governing the procedure for obtaining authorization to construct
new pipeline facilities. In September 1999, the FERC issued a related policy
statement establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates for service on new pipeline facilities
based solely on the costs associated with such new pipeline facilities.

         We cannot predict what further action the FERC will take on these
matters, nor can we accurately predict whether the FERC'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 the
Company in a way that materially differs from the way it affects other
natural gas producers, gatherers and marketers.

         The Outer Continental Shelf Lands Act, which the FERC implements as
to transportation and pipeline issues, requires that all pipelines operating
on or across the Outer Continental Shelf provide open-access,
non-discriminatory service. Historically, the FERC has opted not to impose
regulatory requirements under its Outer Continental Shelf Lands Act authority
on gatherers and other entities outside the reach of its NGA jurisdiction.
However, the FERC recently issued Order No. 639, requiring that virtually all
non-proprietary pipeline transporters of natural gas on the Outer Continental
Shelf report information on their affiliations, rates and conditions of
service. The reporting requirements established by the FERC in Order No. 639
may apply, in certain circumstances, to operators of production platforms and
other facilities on the Outer Continental Shelf, with respect to gas
movements across such facilities. Among the FERC's stated purposes in issuing
such rules was the desire to increase transparency in the market, to provide
producers and shippers on the Outer Continental Shelf with greater assurance
of (a) open-access services on pipelines located on the Outer Continental
Shelf and (b) non-discriminatory rates and conditions of service on such
pipelines.

         The FERC retains authority under the Outer Continental Shelf Lands
Act to exercise jurisdiction over gatherers and other entities outside the
reach of its NGA jurisdiction if necessary to ensure non-discriminatory
access to service on the Outer Continental Shelf. We do not believe that any
FERC action taken under its Outer Continental Shelf Lands Act jurisdiction
will affect us in a way that materially differs from the way it affects other
natural gas producers, gatherers and marketers.

         Additional proposals and proceedings that might affect the natural
gas industry are pending before Congress, the FERC and the courts. The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue.

                                       14
<PAGE>

         SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil,
condensate and natural gas liquids by the Company are not currently
regulated, and are subject to applicable contract provisions made at market
prices. In a number of instances, however, the ability to transport and sell
such products is dependent on pipelines whose rates, terms and conditions of
service are subject to the FERC's jurisdiction under the Interstate Commerce
Act. In other instances, the ability to transport and sell such products is
dependent on pipelines whose rates, terms and conditions of service are
subject to regulation by state regulatory bodies under state statutes.

         The regulation of pipelines that transport crude oil, condensate and
natural gas liquids is generally more light-handed than the FERC's regulation
of gas pipelines under the NGA. Regulated pipelines that transport crude oil,
condensate, and natural gas liquids are subject to common carrier obligations
that generally ensure non-discriminatory access. With respect to interstate
pipeline transportation subject to regulation of the FERC under the
Interstate Commerce Act, rates generally must be cost-based, although
market-based rates or negotiated settlement rates are permitted in certain
circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to
an indexing methodology. Under this indexing methodology, pipeline rates are
subject to changes in the Producer Price Index for Finished Goods, minus one
percent. A pipeline can seek to increase its rates above index levels
provided that the pipeline can establish that there is a substantial
divergence between the actual costs experienced by the pipeline and the rate
resulting from application of the index. A pipeline can seek to charge
market-based rates if it establishes that it lacks significant market power.
In addition, a pipeline can establish rates pursuant to settlement if agreed
upon by all current shippers. A pipeline can seek to establish initial rates
for new services through a cost-of-service proceeding, a market-based rate
proceeding, or through an agreement between the pipeline and at least one
shipper not affiliated with the pipeline. The FERC indicated in Order No. 561
that it will assess in 2000 how the rate-indexing method is operating. The
FERC issued a Notice of Inquiry on July 27, 2000 seeking comment on whether
to retain or to change the existing index. After consideration of all the
initial and reply comments, the FERC concluded on December 14, 2000 that the
PPI-1 index has reasonably approximated the actual cost changes in the oil
pipeline industry during the preceding five year period, and that it should
be continued for the subsequent five year period.

         FEDERAL LEASES. The Company maintains operations located on federal
oil and gas leases, which are administered by the Minerals Management Service
pursuant to the Outer Continental Shelf Lands Act. These leases are issued
through competitive bidding and contain relatively standardized terms. These
leases require compliance with detailed Minerals Management Service
regulations and orders that are subject to interpretation and change by the
Minerals Management Service.

         For offshore operations, lessees must obtain Minerals Management
Service approval for exploration, development 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 assurances can be
substantial, and there is no assurance that they can be obtained in all
cases. Under some circumstances, the Minerals Management Service may require
operations on federal leases to be suspended or terminated.

         The Minerals Management Service also administers the collection of
royalties under the terms of the Outer Continental Shelf Lands Act and the
oil and gas leases issued under the Act. The amount of royalties due is based
upon the terms of the oil and gas leases as well as of the regulations
promulgated by the Minerals Management Service. These regulations are amended
from time to time, and the amendments can affect the amount of royalties that
we are obligated to pay to the Minerals Management Service. However, we do
not believe that these regulations or any future amendments will affect the
Company in a way that materially differs from the way it affects other oil
and gas producers, gathers and marketers.

                                       15
<PAGE>

STATE REGULATIONS

         Most states regulate the production and sale of oil and natural gas,
including requirements for obtaining drilling permits, the method of
developing new fields, the spacing and operation of wells and the prevention
of waste of oil and gas resources. The rate of production may be regulated
and the maximum daily production allowable from both oil and gas wells may be
established on a market demand or conservation basis or both.

         The Company may enter into agreements relating to the construction
or operation of a pipeline system for the transportation of natural gas. To
the extent that such gas is produced, transported and consumed wholly within
one state, such operations may, in certain instances, be subject to the
jurisdiction of such state's administrative authority charged with the
responsibility of regulating intrastate pipelines. In such event, the rates
which the Company could charge for gas, the transportation of gas, and the
construction and operation of such pipeline would be subject to the rules and
regulations governing such matters, if any, of such administrative authority.

LEGISLATIVE PROPOSALS

         In the past, Congress has been very active in the area of natural
gas regulation. There are legislative proposals pending in the various state
legislatures which, if enacted, could significantly affect the petroleum
industry. At the present time it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures
and what effect, if any, such proposals might have on the Company's
operations.

COMPETITION

         The gas and oil industry is highly competitive in all of its phases.
The Company encounters strong competition from other gas and oil companies in
all areas of its operations, including the acquisition of exploratory and
producing properties, the permitting and conducting of seismic surveys and
the marketing of gas and oil. Many of these competitors possess greater
financial, technical and other resources than the Company. Competition for
the acquisition of exploratory or producing properties is affected by the
amount of funds available to the Company, information about producing
properties available to the Company and any standards the Company establishes
from time to time for the minimum projected return on investment. Competition
also may be presented by alternative fuel sources, including heating oil and
other fossil fuels. There has been increased competition for lower risk
development opportunities and for available sources of financing. In
addition, the marketing and sale of natural gas and processed gas are
competitive. Because the primary markets for natural gas liquids are
refineries, petrochemical plants and fuel distributors, prices generally are
set by or in competition with the prices for refined products in the
petrochemical, fuel and motor gasoline markets.

FACILITIES

         The Company leases approximately 7,600 square feet of office space
in Houston, Texas, at an annual rent of $124,548. The lease expires in
September 2001. The Company leases approximately 13,300 square feet of office
space in Corpus Christi, Texas. The annual rent is $168,137, and the Lease
expires on June 30, 2003. The Company currently has more office space than it
needs in Corpus Christi, and has sublet a portion of its office space.

EMPLOYEES

         The Company has nine full-time employees in its Houston, Texas
office, and twenty-five employees in its Corpus Christi, Texas office. Their
functions include management, production, engineering, geology, geophysics,
exploitation, land, legal, gas marketing, accounting, financial planning and
administration. Certain operations of the Company's field activities are
accomplished through independent contractors who are supervised by the
Company. The Company believes its relations with its employees and
contractors are good. No employees of the Company are represented by a union.
The Company believes its relationship with its employees is satisfactory.

                                       16
<PAGE>

ITEM 2.  DESCRIPTION OF PROPERTY

PRINCIPAL AREAS OF OPERATIONS

         The Company owns and operates producing properties located in five
states with proved reserves located primarily in Louisiana and Texas. Daily
production from both operated and non-operated wells net to the Company's
interest averaged 9,290 Mcf per day and 276 Bbls of oil per day for the year
ended December 31, 1999 and 16,055 Mcf per day and 449 Bbls of oil per day
for the year ended December 31, 2000. These properties have provided most of
the Company's revenues to date.

DRILLING ACTIVITY

         From November 1, 1997 (the effective date of the Acquisitions)
through December 31, 1998, 24 exploratory wells were drilled for the
Company's account, of which 12 were completed and 11 were dry holes. In 1999,
23 exploratory and six developmental wells were drilled and logged for the
Company's account of which 22 were completed and seven were dry holes. In
2000, 41 exploratory and 11 developmental wells were drilled and logged for
the Company's account of which 29 were completed as of March 30, 2001, two
were waiting on completion and/or pipelines, and 21 were dry holes.

         The following table sets forth certain information regarding the
actual drilling results for each of the years 1999 and 2000 as to wells
drilled in each such individual year.

<TABLE>
<CAPTION>
                                                   EXPLORATORY               DEVELOPMENT
                                                    WELLS(1)                  WELLS(1)
                                             ------------------------    --------------------
                                                GROSS        NET           GROSS      NET
                                                -----        ---           -----      ---
<S>                                          <C>           <C>           <C>         <C>
       1999
          Productive ........................   16           2.41             6      1.46
          Dry................................    7           0.87           ---       ---
       2000
          Productive.........................   25           5.994            6      1.559
          Dry................................   16           5.275            5      1.412
</TABLE>

--------------------
(1)  Gross wells represent the total number of wells in which the Company
     owned an interest; net wells represent the total of the Company's net
     working interests owned in the wells.


         Through the first quarter of 2001, the Company participated in the
drilling of 11 additional exploratory wells and four additional development
wells, of which one had been completed, five are awaiting completion, two
were dry holes and seven were drilling.

PRODUCTIVE WELL SUMMARY

         The following table sets forth certain information regarding the
Company's ownership as of December 31, 2000 of productive gas and oil wells
in the areas indicated.

<TABLE>
<CAPTION>
                                                                    GAS                     OIL
                                                            --------------------    --------------------
                                                             GROSS        NET        GROSS        NET
                                                            --------    --------    --------    --------
<S>                                                         <C>         <C>         <C>         <C>
           Alabama ......................................      --            --           1         .17
           Kansas .......................................       1           .10          --          --
           Louisiana ....................................       4           .18          --          --
           Oklahoma......................................       4           .13           1         .19
           Texas.........................................      59         10.43          15        1.69
                                                            --------    --------    --------    --------
               Total ....................................      68         10.84          17        2.05
                                                            ========    ========    ========    ========
</TABLE>

VOLUMES, PRICES AND PRODUCTION COSTS

         The following table sets forth certain information regarding the
production volumes, average prices received (net of transportation) and average
production costs associated with the Company's sale of gas and oil for the
periods

                                       17
<PAGE>

indicated.

<TABLE>
<CAPTION>
                                                                         YEAR ENDED DECEMBER 31,
                                                                    -----------------------------------
                                                                         2000                1999
                                                                    ----------------    ---------------
<S>                                                                 <C>                 <C>
  Net Production:
          Oil (Bbl) ............................................        163,892             100,559
          Gas (Mcf).............................................      5,860,195           3,381,592
          Gas equivalent (Mcfe).................................      6,843,547           3,984,946
  Average sales price:
  Oil ($ per Bbl)...............................................    $     32.34(1)      $     18.01(1)
          Gas ($ per Mcf).......................................    $      4.12(1)      $      2.35(1)
  Average production expenses and taxes ($ per Mcfe)............    $      0.48         $      0.35
</TABLE>

  -----------
(1)      Average sales prices do not include the Company's hedging instruments
         for oil and gas. Including the effect of hedging activities, average
         sales prices would have been $29.38 per Bbl and $3.38 per Mcf for the
         year ended December 31, 2000, and $19.01 per Bbl and $2.36 per Mcf for
         the year ended December 31, 1999.

  LEASEHOLD ACREAGE

         The following table sets forth as of December 31, 2000, the gross
and net acres of proved developed and proved undeveloped and unproven gas and
oil leases which the Company holds or has the right to acquire.

<TABLE>
<CAPTION>
                                                      PROVED DEVELOPED    PROVED UNDEVELOPED         UNPROVEN
                                                     -----------------    -------------------    ------------------
      STATE                                           GROSS     NET        GROSS        NET       GROSS       NET
      -----                                          ------    ------     -------     -------    --------   -------
<S>                                                  <C>       <C>        <C>         <C>        <C>        <C>
      Alabama....................................        82        19         ---        ---          113        22
      Arkansas ..................................       ---       ---         ---        ---        6,360     2,544
      Kansas ....................................       640        31         ---        ---          ---       ---
      Louisiana .................................       ---       ---         ---        ---       17,859     3,057
      Mississippi................................        82         7         ---        ---          795       443
      Oklahoma ..................................     2,198        51         ---        ---       12,909     3,727
      Texas .....................................    18,292     4,239       1,180        346      193,017    64,537
                                                     ------     -----       -----        ---      -------    ------
              Total ............................     21,294     4,347       1,180        346      231,053    74,330
                                                     ======     =====       =====        ===      =======    ======
</TABLE>

TITLE TO PROPERTIES

         Title to properties is subject to royalty, overriding royalty,
carried working, net profits, working and other similar interests and
contractual arrangements customary in the gas and oil industry, liens for
current taxes not yet due and other encumbrances. As is customary in the
industry in the case of undeveloped properties, little investigation of
record title is made at the time of acquisition (other than a preliminary
review of local records). Investigations including a title opinion of local
counsel generally are made before commencement of drilling operations. The
Company has granted to Deutsche Bank AG, New York Branch a mortgage or a
right to file a mortgage on virtually all of its gas and oil properties to
secure repayment of its credit facility with the bank.

ITEM 3.  LEGAL PROCEEDINGS

         The Company currently has no action filed against it other than
ordinary routine litigation.

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

         There were no such matters submitted in the fourth quarter of 2001.

                                       18
<PAGE>

                                     PART II

ITEM 5.  MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

         On November 12, 1993, the Company's predecessor, Frontier Natural
Gas Corporation's common stock and its Series A Warrants were admitted to
trading on the NASDAQ Small Cap Market under the symbols "FNGC" and "FNGCW",
respectively. In November of 1998, the Series A Warrants expired. On August
9, 1996, Frontier Natural Gas Corporation's Series B Warrants were admitted
to trading on the NASDAQ Small Cap Market under the symbol "FNGCZ". In May of
1998 the Company reincorporated in the State of Delaware and changed its name
to Esenjay Exploration, Inc. Its common stock trading symbol changed to
"ESNJ" and its Series B Warrant symbol to "ESNJZ". The Series B Warrants
ceased to be listed on the NASDAQ Small Cap Market in February of 1999 due to
insufficient market makers and are not currently listed on any national
market. There have been no reported trades of the Series B Warrants since
that time. The Series B Warrants are exercisable for $12.15 per share of
common stock of the Company, and expire on the earlier of August 8, 2001 or
such time as the stock trades over $24.30 for twenty consecutive days.

         On September 23, 1999, the Company acquired 3DX Technologies Inc.
via merger. The price of the acquisition was approximately $7.4 million, of
which $6.7 million was in the form of Company's common stock and $0.7 million
was in the form of Company preferred stock. As a result, Esenjay issued
356,999 shares of new convertible preferred stock that could be redeemed at
Esenjay's sole option until September 23, 2000 at $1.925 per share. Said
356,999 shares of convertible preferred stock were redeemed by the Company on
September 23, 2000. The convertible preferred stock was listed on the
over-the-counter bulletin board under the symbol "ESNJP". There were no 1999
or 2000 trades reported in this series of preferred stock prior to its
redemption.

         The Company's common stock trades on the NASDAQ Small Cap Market
under the symbol "ESNJ". The Company estimates there are approximately 145
common shareholders of record and 2,977 beneficial owners of the common stock.

         The following table sets forth, for the periods indicated, the high
and low sales prices of the Company's Common Stock as reported on the Nasdaq
Small-Cap Market.

<TABLE>
<CAPTION>
             Quarter Ended                   High            Low
             -------------------------     ---------      ----------
<S>                                        <C>           <C>
             December 31, 2000              $ 5 3/16         $ 3 1/8
             September 30, 2000                4 3/4         2 15/32
             June 30, 2000                     4 1/8           1 5/8
             March 31, 2000                    2 3/4          1 9/16

             December 31, 1999               $ 2 3/8        $ 1 7/16
             September 30, 1999                2 5/8           1 3/4
             June 30, 1999                   2 11/16           1 1/8
             March 31, 1999                    2 7/8               1
</TABLE>

         To date, the Company has not paid any dividends on its Common Stock.
The payment of dividends, if any, in the future is within the discretion of
the Board of Directors and will depend upon the Company's earnings, its
capital requirements and financial condition and other relevant factors.
Payments of dividends are also restricted in certain situations by the Company's
credit agreement with Deutsche Bank. The Company does not expect to declare or
pay any dividends on its Common Stock in the foreseeable future.

ITEM 6.  MANAGEMENT'S DISCUSSION AND ANALYSIS

         The following discussion and analysis reviews Esenjay Exploration,
Inc.'s operations for the twelve month periods ended December 31, 2000 and
1999 and should be read in conjunction with the consolidated financial
statements and notes related thereto. Certain statements contained herein
that set forth management's intentions, plans, beliefs, expectations or
predictions of the future are forward-looking statements. It is important to
note that

                                       19
<PAGE>

actual results could differ materially from those projected in such
forward-looking statements. The risks and uncertainties include but are not
limited to potential unfavorable or uncertain results of 3-D seismic surveys
not yet completed, drilling costs and operational uncertainties, risks
associated with quantities of total reserves and rates of production from
existing gas and oil reserves and pricing assumptions of said reserves,
potential delays in the timing of planned operations, competition and other
risks associated with permitting seismic surveys and with leasing gas and oil
properties, potential cost overruns, potential dry holes and regulatory
uncertainties and the availability of capital to fund planned expenditures as
well as general industry and market conditions.

OVERVIEW

         A summary of the impact of the successful efforts accounting method
as it relates to the Acquisitions and a survey of the Company's history are
as follows:

         SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company
utilizes the successful efforts method of accounting. Under this method it
expenses its exploratory dry hole costs and the field acquisition costs of 3-D
seismic data as incurred. The undeveloped properties, which were acquired
pursuant to the Acquisitions, were comprised primarily of interests in
unproven 3-D seismic based projects, and were recorded in May of 1998 at an
independently estimated fair market value of $54.2 million as determined by
Cornerstone Ventures, L.P., a Houston, Texas based investment banking firm.
Pursuant to the successful efforts method of accounting, the Company is
amortizing such initial costs of unproved properties on a straight-line basis
over a period not to exceed forty-eight months, as well as recognizing
property specific impairments. As of December 31, 2000 the unamortized balance
was $5,334,700. In 2000 this amortization resulted in a $5,176,100 expense and
impairments totaled an additional $4,771,272. Impairments were primarily
related to unproved property costs on projects regarding which management
believes have diminished value based upon 2000 exploratory activities. Hence
significant non-cash charges primarily related to the accounting treatment of
the Company's unproven properties have depressed reported earnings of the
Company and will likely continue to do so in 2001; however, the non-cash
charges will not affect cash flows provided by operating activities nor the
ultimate realized value of the Company's natural gas and oil properties. The
amortization of properties acquired pursuant to the Acquisitions will conclude
not later than May of 2002.

         As a result of the tax rules applicable to the Acquisitions, the
Company will likely not be able to fully use that portion of its existing net
operating loss carry forward attributable to periods prior to May of 1998 in
the future.

         OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH DECEMBER 31,
1998. Prior to May of 1998 the Company operated on a much smaller scale. A
negotiation process led to the Company entering into the Acquisition Agreement
among the Company, EPC, and Aspect. This Acquisition Agreement required
approval of the shareholders of the Company. At a special meeting of
shareholders held on May 14, 1998 the shareholders approved the Acquisition
Agreement, a recapitalization of the Company pursuant to which each
outstanding share of common stock would convert into one-sixth (1/6) of a
share of new common stock (the "Reverse Split"), a plan and agreement of
merger pursuant to which the Company would reincorporate in the state of
Delaware and would change its name to Esenjay Exploration, Inc. (the
"Reincorporation"), and the election of seven directors. Immediately after the
shareholders meeting, the Company closed the transactions provided for in the
Acquisition Agreement, implemented the Reverse Split, and completed the
Reincorporation. The result of the foregoing is that the Company conveyed a
substantial majority of its Common Stock to acquire an array of significant
technology enhanced natural gas oriented exploration projects. The Company
believed the Acquisitions would facilitate expanded access to capital markets
due to the value and diversity of its exploration project portfolio. The
Company also believes the transactions significantly enhanced the Company's
management team.

         On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering
the Company had 15,762,723 shares outstanding.

         OVERVIEW OF 1999 ACTIVITIES. As a result of the above-described
acquisitions, restructuring, and the underwritten offering, the Company
believed it was, and believes it continues to be, positioned for a period of
significant exploration activity on its technology enhanced projects. Many of
the projects had reached the drilling stage. In many instances the requisite
process of geological and/or engineering analysis, followed by acreage
acquisition of leasehold rights and seismic permitting, and 3-D seismic field
data acquisition, then processing of the data and finally its interpretation,
required several years and the investment of significant capital. Management

                                       20
<PAGE>

believes the acquisition of projects at this advanced stage has not only
reduced the drilling risk, but also positioned the Company to consistently
drill on a broad array of exploration prospects for years to come.

         The Company ended 1999 having gone from nominal third quarter 1998
gas and oil revenues of approximately $35,000 per month and large operating
cash flow deficits to a company which averaged $1,815,637 per month in net
oil and gas revenues in the fourth quarter of 1999. The increasing revenue
allowed the Company to achieve positive operating cash flow (before capital
expenditures, and before the costs of acquisition of new 3-D seismic data,
and changes in working capital) in the third quarter, which operating cash
flow increased in the fourth quarter.

         On May 12, 1999, the Company announced that it had entered into a
Plan and Agreement of Merger with 3DX Technologies, Inc. ("3DX") which
provided for the merger of 3DX into the Company. The shareholders of both
companies approved the transaction at their respective meetings on September
23, 1999 and the merger was consummated the same day. The terms of the merger
provided for 3DX shareholders to receive, at their election, either (i) the
issuance of one share of Esenjay common stock for 3.25 shares of 3DX common
stock; or (ii) the issuance of a new Esenjay convertible preferred stock at a
ratio of one share of Esenjay convertible preferred stock for each 2.75 shares
of 3DX common stock. The preferred stock did not require payment of dividends.
Approximately 91% of the 3DX common shares converted into Esenjay common stock
and approximately 9% were converted into Esenjay convertible preferred stock.
As a result, Esenjay issued approximately 2,906,800 new shares of common stock
and 356,999 shares of convertible preferred stock. The convertible preferred
stock was redeemable at Esenjay's sole option until September 23, 2000 at
$1.925 per share. It was subsequently redeemed in September of 2000.

         OVERVIEW OF 2000 ACTIVITIES. In 2000 the Company utilized its
increased cash resources to increase its capital expenditures to
approximately $25 million. The increased available capital allowed the
Company to focus drilling on higher risk, higher potential opportunities.
This risk profile led to the drilling of the Company's Runnells #3 discovery
well located in the Duncan Slough project area in the fourth quarter of 2000
and its Pereira Children's Trust #2 well located in the Hordes Creek project
area that was logged and completed in the first quarter of 2001. The Pereira
Childrens Trust #2 well has subsequently been renamed the Hamman & Anderson
#2 well. Both discoveries will be the focus of significant capital investment
in 2001 as field delineation wells are drilled.

         In 2000 the Company participated in a total of 52 new wells that
reached total depth and were logged during the year. Of the total wells
drilled and logged during 2000, 29 were completed as of March 31, 2001, two
are scheduled to commence production upon completion and pipeline
connections, and 21 were dry holes.

         The Company added 19.256 billion cubic feet equivalent ("BCFE") of
new gas and oil reserves from its 2000 drilling activities. The added
reserves do not reflect the full potential of the Grand Slam Field
anticipated to be ascertained through the delineation wells to be drilled in
2001, nor does it reflect any reserves attributable to the Hordes Creek Field
which was not discovered until the first quarter of 2001. Year end 2000
reserves were adversely affected by 6.241 BCFE of downward adjustments in
prior discoveries primarily related to wells located in the Hackberry trend.
The Hackberry wells were previously believed by Company engineers and by the
Company's independent reservoir engineers to be primarily depletion drive
reservoirs but actual results showed a stronger water drive component that
shortened the wells' lives and led to the downward adjustments. These
adjustments are incorporated in the December 31, 2000 gas and oil reserve
studies. Year end totals were also affected by the sale of 3.398 BCFE
pursuant to a transaction with an industry partner closed in early 2000.

         On September 23, 2000, the Company redeemed all of its previously
outstanding preferred stock. The redemption was pursuant to a unilateral
right to redeem in favor of the Company. A total of 356,999 shares of
preferred stock were redeemed at the contractual redemption price of $1.925
per share.

         On October 12, 2000 the Company finalized and closed an agreement
with 420 Energy Investments, Inc. ("420") pursuant to which $864,000 in
non-recourse debt and $562,034 in interest on non-recourse debt was
satisfied. Consideration paid to 420 was $300,000 in cash, plus an agreement
to drill one well in the project area, plus an agreement to pay to 420 cash
payments on the date drilling may commence on any future wells it may drill
on one exploration project area located in Terrebonne Parish, Louisiana. Any
such future payments would range from $20,000 per well to $100,000 per well,
but would never exceed a total of $300,000. In addition, 420 retained

                                       21
<PAGE>

its prior right to an overriding royalty equal to 2% of the Company's interest
in any well drilled in the project area in Terrebonne Parish. As a result of
the transaction, the Company recognized an extraordinary gain in the fourth
quarter of 2000 of $1,126,034. The initial well quarter in which the Company
participated was drilled in the fourth. It elected to not participate in
completion of the well due to what the Company believed were marginal expected
economics. The Company has no obligation or any current plans to drill any
future wells on the project acreage.

         On October 2, 2000 the Company announced it had retained Deutsche
Bank Securities, Inc. to advise it concerning various strategic alternatives
intended to better maximize shareholder value. It also retained the firm of
Randall & Dewey, Inc. to initiate and manage a transaction to seek to better
realize this value through various alternatives such as selling the Company
for cash, merger, stock trade or acquisition. Since the Company's recent
field discoveries, the Company has determined that it can better maximize
shareholder value by drilling delineation wells near the discoveries and
executing its overall exploratory drilling plan. Accordingly, it has
announced that it does not plan to actively pursue new alternatives for a
potential sale of the Company.

         OVERVIEW OF 2001 ACTIVITIES. The Company believes it entered 2001 in
a position to continue to expand its production and reserves via exploration
activities on its technology-enhanced projects. By utilizing the increased
capital available to it from operating cash flow, financings and industry
partner transactions, the Company intends to pursue an aggressive exploration
budget in its major trends of activity. The Company's net daily production
approximated 364 barrels of oil per day and 16,681 Mcf natural gas per day in
March of 2001. Subsequent to December 31, 2000, the Company reset its credit
facility with Deutsche Bank AG, New York Branch. Availability pursuant to the
facility was increased to $29 million with a borrowing base adjustment
scheduled for the end of the second quarter of 2001. The facility is divided
into two tranches. Tranche A is a revolving credit facility with $20 million
available of which $14.84 million was outstanding on March 29, 2001. No
principal amortization is required on Tranche A in 2001. Tranche B is a $9
million loan that amortizes in four equal principal payments beginning April
30, 2001. As a result of its current operating cash flow combined with
available credit and the proceeds of anticipated sales of select Exploration
Project interests to industry partners, the Company believes it is positioned
to fund its 2001 drilling and exploration activities, the results of which
are intended to continue the upward trends of increasing cash flow and
reserves. The Company will look to a variety of sources in addition to
operating cash flow to further supplement its capital expenditures budget,
including its credit facilities and sales of additional promoted project
interests to industry partners, as it seeks to maximize its interests and
manage its risks while aggressively pursuing its exploration projects.

         The Company has budgeted $26 million in drilling, completion, land
and seismic expenditures on interests in over 50 wells in 2001. Through this
exploration program, the Company believes it can continue its trends of
growth in net production, net revenues, operating cash flow, and net gas and
oil reserves throughout the year 2001 and beyond. Its 2001 drilling activity
will primarily be divided between a continuation of exploratory drilling on
high potential target features, which drilling will be coupled with the field
delineation and development drilling associated with the Company's recent
field discoveries. An array of lower risk prospects will also be drilled, the
cost of which will be a modest portion of the capital budget.

         As of March 30, 2001, the Company has 18,980,698 total shares of
common stock outstanding. It employs thirty-four full time employees,
including five in its exploration and geophysical departments, seven in its
operations department, two in its exploitation department, and seven in its
land department. Its focus continues to be the implementation of its business
strategy as set forth in this section.

COMPARISON OF 2000 TO 1999.

VOLUMES, PRICES AND PRODUCTION COSTS

         The following table sets forth certain information regarding the
production volumes, average prices received (net of transportation) and
average production costs associated with the Company's sale of gas and oil
for the periods indicated.

                                       22
<PAGE>

<TABLE>
<CAPTION>
                                                                         YEAR ENDED DECEMBER 31,
                                                                  ------------------------------------
                                                                        2000                 1999
                                                                  --------------       ---------------
<S>                                                               <C>                  <C>
Net Production:
         Oil (Bbl) .......................................            163,892               100,559
         Gas (Mcf) .......................................          5,860,195             3,381,592
         Gas equivalent (Mcfe) ...........................          6,843,547             3,984,946
Average sales price:
         Oil ($ per Bbl)..................................        $     32.34(1)       $      18.01(1)
         Gas ($ per Mcf) .................................        $      4.12(1)       $       2.35(1)
Average production expenses and taxes ($ per Mcfe)........        $      0.48          $       0.35
</TABLE>

------------
(1)      Average sales prices do not include the Company's hedging instruments
         for oil and gas. Including the effect of hedging activities, average
         sales prices would have been $29.38 per Bbl and $3.38 per Mcf for the
         year ended December 31, 2000, and $19.01 Bbl and $2.36 per Mcf for the
         year ended December 31, 1999.

         REVENUES. Total revenues increased 176% from $12,566,165 for the
year ended December 31, 1999 to $34,674,753 for the year ended December 31,
2000. This is primarily attributable to the increases in gas and oil revenue,
gain on sale of assets, and other revenues as more fully described below,
which increases were partially offset by an increase in the realized loss on
commodity transactions as more fully described below.

         GAS AND OIL REVENUES. Total gas and oil revenues increased 201% from
$9,781,352 reported in 1999 to $29,446,832 in 2000. The increase in gas and
oil revenue was attributed mainly to increases in quantities of natural gas
and oil produced net to the Company's account and increases in the prices for
which said production was sold. Volumes increased 72% from 3,984,946 MCFE
produced in 1999 to 6,843,547 MCFE in 2000. The average price received per
barrel of oil sold increased from $18.01 to $32.34. The average price
received per MCF of natural gas sold increased from $2.35 to $4.12.

         GAIN ON SALE OF ASSETS. There was an increase of 316% in gain on
sale of assets of $7,086,120 from $2,243,511 reported in 1999 to $9,329,631
in 2000. This was primarily attributable to the gain on the sale of an
interest in the Company's Raymondville Project to an industry partner of
approximately $6,607,211 and the recognition of the gain on sale of an
interest in its Papalote Project to an industry partner of $1,797,707.

         OPERATING FEES. Operating fees increased due to increases of both
exploratory and developmental wells operated, which has resulted in the
increase of operating fees of 32% from $344,539 for the year ended 1999 to
$454,016 for the year ended 2000.

         REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. The Company realized
losses from various commodity hedges of $4,842,372 for the year ending 2000,
and realized a gain of $146,337 for the same period in 1999. The gains or
losses realized are primarily attributable to various transactions in which
the Company hedged future gas and oil delivery obligations. The gains
realized during 1999 were attributed to the Company's average hedge pricing
exceeding the spot market prices for the period. The losses realized during
2000 were incurred as average spot market prices for the period exceeded the
average hedge prices. The size of the loss in 2000 was primarily the result
of the rapid rise in spot natural gas prices during the year.

         OTHER REVENUES. The Company had other revenues of $286,646 for the
year 2000 as compared with $50,426 for the year of 1999. This increase was
primarily due to increased interest income from overnight investments.

         COSTS AND EXPENSES. Total costs and expenses increased 90% from
$22,816,403 in 1999 to $43,335,391 in 2000. The most significant changes
relate to various facets of increased production volumes and increased
exploration activity. Increased production volumes resulted in increases in
lease operating expense, production taxes and depletion as more fully
described below. Increased exploration activities led to increases in
geological and geophysical costs, dry hole expenses and impairments as more
fully described below. Increases in general and administrative costs and
interest expense also related to the increased activity level of the Company
in 2000. Other changes in costs and expenses are described below.

         AMORTIZATION OF UNPROVED PROPERTIES decreased 31% to $5,176,100 in
2000 from $7,546,000 for 1999. The Company is amortizing the undeveloped and
unevaluated value of the properties acquired pursuant to the Acquisition
Agreement between the Company, EPC and Aspect over a period not to exceed
forty-eight months. The

                                       23
<PAGE>

amounts are amortized until the applicable properties are moved into the
proven property base or reduced to zero by amortization or impairment. The
lower amount of such costs incurred in 2000 is the result of the reductions
in the size of the amortization pool in 2000 as compared to 1999. As of
December 31, 2000, a $5,334,700 balance remained in this amortization pool.
(Also see Overview - Successful Efforts Accounting and Related Matters.)

         IMPAIRMENT OF GAS AND OIL PROPERTIES was $4,771,272 in 2000 compared
to $358,106 in 1999. Management periodically reviews each individual
Exploration Project which can result in the decision to expense the book
value of certain projects based upon the belief that they no longer have a
realistic potential to realize the book value from such projects in the
future. Major impairment increases of 1232% in 2000 were primarily the result
of fourth quarter impairments recognized on two project areas as a result of
recent unfavorable drilling results in the project areas. The primary
impairments were a $2,132,577 impairment recognized against the value of the
Lapeyrouse Project Area and an $809,234 impairment recognized against the
Mathis Project Area. Other impairment increases resulted from the increased
activity level in 2000.

         EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL increased 189% from
$1,597,372 for 1999 to $4,613,603 for 2000. These exploration costs reflect
the costs of topographical, geological and geophysical studies and include
the expenses of geologists, geophysical crews and other costs of acquiring
and analyzing 3-D seismic data. The Company's technology-enhanced exploration
program on the Exploration Projects requires the acquisition and
interpretation of substantial quantities of such data. The Company considers
3-D seismic data a valuable asset; however, its successful efforts accounting
method requires such costs to be expensed for accounting purposes. The cash
flow statement does not permit expenditures for geological and geophysical
costs to be included as an oil and gas investing activity or as an add back
to operating activities.

         EXPLORATION COSTS - DRY HOLE was $7,114,950 for 2000 compared to
$692,642 for 1999. This 927% increase was the result of an increase in both
the number and the average cost of dry holes. In 2000 the Company drilled a
higher percentage of higher risk, higher reward wells. This was a foreseeable
cost increase as the Company sought the higher returns from more costly
exploration. The expectation is that the greater gas and oil reserves
discovered in this drilling profile would create higher ultimate, overall
returns. During 2000, the Company participated in the drilling of 21 wells
which were dry holes.

         GENERAL AND ADMINISTRATIVE EXPENSES increased 26% from $5,713,408
for 1999 as compared to $7,187,619 for 2000. The cost increases were
primarily attributable to the Company's active drilling program combined with
its efforts to expand its project inventory. In addition, $635,580 of the
increase was due to payment of a bonus to all employees in 2000, which bonus
was not paid in 1999. Increased costs were also incurred in the land and
financial areas as the Company took steps to enhance its systems and
abilities in both areas.

         DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 124%
from $4,292,837 for 1999 to $9,635,671 in 2000. The increase was primarily
attributed to an increase in volumes produced, and to high depletion costs
per unit produced from the Company's Hackberry wells in 2000. Downward
reserve revisions in late 2000 regarding the Company's Hackberry production
increased the unit costs of depletion in the Hackberry in 2000. (Also see
Overview - Overview of 2000 Activities.)

         INTEREST EXPENSE increased 56% from $871,501 for 1999 to $1,361,533
for 2000. The increase in interest expense was primarily attributable to the
Company's usage of its expanded credit facility with Deutsche Bank AG. The
Company capitalized a large portion of its interest associated with ongoing
projects, of which capitalized amounts totaled $1,023,221 and $219,197 for
the respective years ending 1999 and 2000.

         PRODUCTION TAXES increased 222% from $655,145 for 1999 to $2,107,093
for 2000. The increase in production taxes was the result of increased net
volumes produced, and further significantly increased by increased sales
revenues due to natural gas price increases throughout 2000.

         LEASE OPERATING EXPENSE increased 56% from $752,861 for 1999 to
$1,172,590 for 2000. This increase is attributable to an increase in the
number of producing wells in 2000, and to the number of wells drilled,
completed and placed into production in 2000. The addition of producing wells
acquired through the 3DX merger for the full year of 2000 also contributed to
this increase.

                                       24
<PAGE>

         DELAY RENTAL EXPENSE decreased 42% from $336,531 for 1999 to
$194,960 for 2000. This cost is primarily attributable to rentals payable on
leases acquired for projects and prospects not yet developed but which were
determined to be a part of the Company's proved undeveloped reserves.

         EXTRAORDINARY GAIN. Extraordinary gain during 2000 was the result of
the settlement of the non-recourse debt and accrued interest with 420-Energy
Investments, Inc. There were no extraordinary items during 1999.

         NET LOSS PER COMMON SHARE. Net loss per common share decreased from a
net loss of $0.62 per share for 1999 to $0.40 per share for 2000. Due to the
factors discussed above, there was a $2,715,634 decrease in net loss
applicable to common stockholders of $7,534,604 for 2000 as compared to 1999.
The increase of weighted average number of common equivalent shares at
December 31, 2000 of approximately 2,265,000 shares as compared to 1999 also
affected the per share calculations. The common shares related to the 3DX
merger were outstanding all of 2000, thereby increasing the weighted average
number outstanding as compared to the partial year 1999. Approximately
18,877,000 weighted average common equivalent shares were outstanding at
December 31, 2000 as compared with approximately 16,612,000 at December 31,
1999.

KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE
OPERATING RESULTS.

         The Company's future operating results will continue to be
substantially dependent upon the success of the Company's efforts to develop
the projects acquired in the Acquisitions and thereafter.

         Management continues to believe these projects represent the most
promising prospects in the Company's history. Production from wells drilled
from 1998 through the present on projects acquired pursuant to the
Acquisitions continue to substantially increase the Company's revenues.
Conversely, the capital expenditures planned in 2001 will continue to require
substantial outlays of capital to explore, develop and produce. Drilling
results for 1998 and 1999 resulted in substantial production increases in
those years. The Company believes the field delineation and development
drilling which will comprise a significant portion of its 2001 capital
expenditures plan enhance the likelihood of significant increases in its net
daily production throughout 2001.

LIQUIDITY AND CAPITAL RESOURCES

         The Company business plan calls for net expenditures of $26 million
in drilling, completion, land and seismic costs for 2001. These budgeted
amounts are based upon exploration opportunities and may be adjusted based
upon available capital, new opportunities and industry conditions. The
Company's sources of financing include borrowing capacity under its credit
facilities, the sale of promoted interests in the Exploration Projects to
industry partners and cash provided from operations.

         The Company entered 2001 having gone from nominal second quarter
1998 gas and oil production revenues of approximately $35,000 per month and
large operating cash flow deficits to a company which averaged over
$3,500,000 per month in gas and oil revenues in the fourth quarter of 2000.
Gas and oil production is expected to continue to increase as new gas and oil
production from wells drilled in 2000 and 2001 continues to come on line.
Additional success in 2001 on wells currently drilling would continue the
trend of increasing production. This should allow the Company to achieve
steadily increasing operating cash flow (prior to capital expenditures and
new 3-D seismic data acquisition costs, which costs the successful efforts
accounting method utilized by the Company mandate to be expensed rather than
capitalized). These increases could be limited to the extent offset by
potential decreases in the sales price of gas or oil produced.

         The Company ended 2000 with a deficit working capital of
approximately $4.7 million. Of this amount approximately $6.8 million was
represented by the current portion of its long term debt. The Company's
borrowing base pursuant to Tranche A was increased to $20,000,000 on April 16,
2001. Pursuant to the total Deutsche Bank credit facility, $29 million is now
available.

         The credit facility with Deutsche Bank continues in two tranches;
$20 million under Tranche A and $9 million under Tranche B. Tranche A is a
revolving facility with no required principal payments until 2002, at which
time it converts into a 60-month term loan. Tranche B is payable interest
only until the second quarter of 2001, at

                                       25
<PAGE>

which time the principal is amortized at a rate of 25% per quarter until
fully repaid. Both loans are at a varied interest rate utilizing either
Deutsche Bank's alternative interest rate or the London interbank rate plus
2% for both Tranche A and Tranche B. As of March 31, 2001, $14.84 million was
drawn under Tranche A and $9 million under Tranche B. All undrawn funds will
be available for future activities of the Company. The facility is secured by
a mortgage on most proven properties currently owned by the Company. In
addition, the Company has a negative pledge and an agreement to mortgage any
of the Company's unproven projects or properties at the demand of the bank.
In addition to the foregoing, Deutsche Bank AG received a 1.5% overriding
royalty interest, proportionately reduced to the Company's net interest, on
the gas and oil properties classified as proven as of the date of initial
closing on January 24, 2000, and an agreement that the Company would convey
to the bank a 1.5% overriding royalty interest, proportionately reduced to
the Company's net interest, on future proven wells on the date any such
future wells are logged, for as long as funds are outstanding pursuant to
Tranche B. In the event the Tranche B loans are repaid in full prior to April
30, 2002, the Company may redeem the overriding royalty interests conveyed to
Deutsche Bank AG for an amount equal to (a) an amount which, when added to
the interest paid to Deutsche Bank AG, plus revenues received by Deutsche
Bank AG from the overriding royalties conveyed to Deutsche Bank AG, would
provide to Deutsche Bank AG an internal rate of return of approximately 15%,
plus (b) 60% of the then remaining present value of the overriding royalties
to be redeemed after subtracting the amount calculated in (a) above. In
addition, Deutsche Bank also received on January 24, 2000 a five-year warrant
to purchase 250,000 shares of the Company's common stock at a price equal to
$1.50 per share. The Company expects further increases in the Tranche A
borrowing base in the event its proven oil and gas reserves continue to grow.
Its 2001 business plan calls for a reduced need for additional credit in
2001. As such, certain of the growth anticipated in Tranche A of the facility
during 2001 and 2002 is intended to be used to amortize the Tranche B debt
prior to April 30, 2002. This plan would allow for most of the Company's
operating cash flow (prior to capital expenditures and new 3-D seismic data
acquisition costs) to be utilized to fund the Company's capital budget in
2001.

         Pursuant to the Company's credit agreement with Deutsche Bank, it
has certain covenants regarding current interest coverage ratios and other
covenants regarding which it is expected to be in compliance at the end of
each quarter. Although the Company believes it can be in compliance with
these covenants in the year 2001, there can be no assurance that it will be
in compliance. In the event it is not in compliance, the Company will be
required to seek waivers of said covenants or would be required to seek
alternative financing arrangements.

         Effective January 1, 2001, Statement of Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" became
effective. At current natural gas prices, the effect will be a balance sheet
charge named Other Comprehensive Income ("OCI"), which will reduce total
equity to less than $20,000,000 in 2001. Depending upon the classification of
the nature of certain of the Company's derivatives, a portion of this charge
could be taken through the income statement in a category named Unrealized
Gain or Loss from Commodity Transactions. OCI will likely materially increase
or decrease from period to period for the Company based upon then current
market prices of natural gas and oil. The Company has a covenant with
Deutsche Bank that its tangible net worth will equal or exceed, at all times,
$20,000,000. It has requested that Deutsche Bank exclude the effect of OCI,
and the effect of other non-cash charges resulting from this change in
standard, from the compliance calculation. Deutsche Bank has advised the
Company that it intends to complete appropriate amendments to the covenant to
negate the effect of such charges on compliance as of March 31, 2001. In the
event this is not done, the Company would likely not be in compliance during
parts of 2001.

         The Company historically has addressed its long-term liquidity needs
through the issuance of debt and equity securities, through bank credit and
other credit facilities, sales of project interests to industry partners and
with cash provided by operating activities. Its major obligations as of March
2001, consisted principally of (i) servicing loans under the credit
facilities with Deutsche Bank and other loans, (ii) funding of the Company's
exploration activities, and (iii) funding of the day-to-day operating costs.

         The Company has an ambitious capital expenditure plan for 2001,
which includes approximately $26 million in drilling, completion, land and
seismic costs for the year. Cash on hand, cash available pursuant to the
Deutsche Bank credit facility, and cash flow from operations will contribute
significantly to said budgets. These

                                       26
<PAGE>

funds may be supplemented by the sale of project interests to industry
partners for the purpose of managing exposure to individual wells and/or to
increase available cash.

         The Company expects to fund a substantial portion of its 2001
capital budget from its cash flow from operations. Its increased daily net
production in 2000 has combined with the industry-wide increase in natural
gas prices in 2000 to significantly increase Company revenues. It anticipates
greater increases in its 2001 net production due to continued drilling, in
particular the addition of delineation and development wells to its drilling
plan. These wells, planned in relation to its Runnells #3 discovery of the
Grand Slam Field and its Pereira Children Trust #2 discovery (recently
renamed the Hamman & Anderson #2 well) of the Hordes Creek Field, represent a
lower risk profile at locations where the production infrastructure is
already installed at adjacent locations. The lower risk profile enhances the
likelihood of success and the infrastructure decreases the time to market.
The Company expects this delineation and development drilling activity,
combined with its ongoing exploratory drilling program, to lead to increased
net daily production throughout 2001. This, in turn, would lead to increased
capital resources throughout the year. In the event net daily production does
not increase, or lower product prices offset the potential revenue from
greater production, or both, the Company would be more dependent upon sales
of project interests to industry partners or credit facilities to support its
capital budget. If such sources were not available, the capital budget would
then have to be adjusted.

         Many of the factors that may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control,
including, but not limited to, oil and natural gas prices, governmental
actions and taxes, the availability and attractiveness of financing and its
operational results. The Company continues to examine alternative sources of
long-term capital, including the acquisition of a company with producing and
exploratory properties for common stock or other equity securities, and also
including bank borrowings, the issuance of debt instruments, the sale of
common stock or other equity securities, the issuance of net profits
interests, sales of promoted interests in its Exploration Projects, and
various forms of joint venture financing. In addition, the prices the Company
receives for its future oil and natural gas production and the level of the
Company's production will have a significant impact on future operating cash
flows.

         The Company markets its natural gas through monthly spot sales.
Because sales made under spot sales contracts result in fluctuating revenues
to the Company depending upon the market price of gas, the Company may enter
into various hedging agreements to minimize the fluctuations and the effect
of price declines or swings. The Company had hedge agreements in place
covering January 2001 natural gas production of 7,191 MMBtu/day at
$2.45/MMBtu and covering 5,000 MMBtu/day at $4.01/MMBtu. It also had a hedge
agreement in place covering January 2001 oil production 175 barrels of oil
per day at $21.03/barrel. Hedge agreements were in place covering 5,000
MMBtu/day of February and March 2001 natural gas production at $4.01/MMBtu.
It also had a natural gas collar in place covering 7,500 MMBtu/day of
February and March 2001 natural gas production, which collar was comprised of
a $3.25 put or floor and a $4.00 call or cap. In February and March 2001, oil
production totaling 175 barrels of oil per day was hedged at $21.03/barrel.

         The Company currently has 5,000 MMBtu/day of natural gas production
hedged at $4.01/MMBtu for the second, third and fourth quarters of 2001. It
also has 7,900 MMBtu/day of second quarter 2001 natural gas production and
8,000 MMBtu/day of third and fourth quarter 2001 natural gas production
covered by a collar with a $3.25 floor and a $4.00 cap. Oil production hedged
at $21.03/barrel totals 168 barrels per day, 161 barrels per day and 154
barrels per day in the second, third and fourth quarters, respectively, of
2001. It also has a collar position in place on natural gas production in
2002 and 2003 covering volumes that range from 4,500 MMBtu/day to 8,500
MMBtu/day which position is at a $3.25 floor and a $4.00 cap. As a result of
the above-referenced transactions, the Company has hedged varying quantities
of its natural gas and oil production through December of 2003. First quarter
2001 hedges are estimated to approximate 76.6% of the Company's natural gas
and 50.5% of its oil production for such quarter. Future percentages will
vary.

         WORKING CAPITAL. At December 31, 2000, the Company had a cash
balance of $3,002,700, total current assets of $19,569,894, and total current
liabilities of $24,259,767. This resulted in a working capital deficit of
$4,689,873. Were the current portion of long term debt due to Deutsche Bank
AG not included in current liabilities, the working capital surplus would
have been $2,060,127. The current portion of long term debt at December 31,
2000 was comprised of $6,750,000 of Tranche B debt due to Deutsche Bank within
one year.

                                       27
<PAGE>

The Company expects to service a $2,250,000 Tranche B principal obligation in
the second quarter of 2001 with advances under Tranche A. Given an expected
mid-year increase in Tranche A availability, third and fourth quarter Tranche
B obligations would be satisfied in the same manner. The Company expects its
trend of increasing gas and oil revenues will continue the growth in revenues
in excess of the ongoing costs of operations, which may also enhance the
Company's working capital position. The net working capital can be negatively
effected by the Company's continuing aggressive capital expenditures program
on its exploration projects or by decreases in natural gas or oil prices. To
the extent a working capital shortfall develops due to capital expenditures
exceeding available cash, including cash generated from operations, it could
be addressed with cash proceeds from sales of interests in Exploration
Projects to industry partners or by adjustments to the capital budget, or by
other sources of capital believed available.

         SUMMARY. The Company believes it is positioned to continue to expand
its exploration activity on its technology enhanced projects. Many of the
projects have reached the drilling stage. In addition, two recent discoveries
provide significant opportunities to drill field delineation wells in 2001.
Successful delineation wells can create additional developmental drilling
opportunities that can allow for continuous expansion of the company's
monthly net gas and oil production in a more predictable manner than during
2000 when there was a greater concentration of higher risk exploratory
drilling. In 2001 the Company plans to expand its delineation and
developmental drilling while continuing its aggressive exploratory drilling
program on high potential geologic features. The Company controls an array of
Exploration Projects regarding which the requisite process of geological
and/or engineering analysis, followed by acreage acquisition of leasehold
rights and seismic permitting, and 3-D seismic field data acquisition, then
processing of the data and finally its interpretation has been completed.
Management believes that its mix of delineation, development and exploratory
drilling positions it for dramatic growth in its proven natural gas and oil
reserves in 2001.

         The Company expects to fund significant portions of its $26 million
year 2001 exploration budget from operating cash flow (prior to capital
expenditures and new 3-D seismic data acquisition costs). Its total capital
budget will be funded from anticipated cash flow and credit facilities, and
supplemented with proceeds from selected sales of interests in its
Exploration Projects to industry partners. The Company will utilize a variety
of sources to fund its continuing capital expenditures budget including
operating cash flow, currently available credit facilities and certain sales
of promoted project interests to industry partners, as it seeks to maximize
its interests and manage its risks while aggressively pursuing its
exploration projects.

         RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In June 1998, Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133) was issued. The Company
adopted SFAS 133 effective January 1, 2000. SFAS 133 requires that all
derivatives be recognized as either assets or liabilities and measured at
fair value, and changes in the fair value of derivatives be reported in
current earnings, unless the derivative is designated and effective as a
hedge. If the intended use of the derivative is to hedge the exposure to
changes in the fair value of an asset, liability or firm commitment, then
changes in the fair value of the derivative instrument will generally be
offset in the income statement by the change in the hedged item's fair value.
However, if the intended use of the derivative is to hedge the exposure to
variability in expected future cash flows, then changes in the fair value of
the derivative instrument will generally be reported in Other Comprehensive
Income (OCI). The gains and losses on the derivative instrument that are
reported in OCI will be reclassified to earnings in the periods in which
earnings are impacted by the hedged item.

         In accordance with the transition provisions of SFAS 133 on January
1, 2001, the Company recorded a cumulative-effect type adjustment of
($14,909,492), in OCI to recognize the fair value of all derivatives that are
designated as cash-flow hedges. This adjustment will change from period to
period, either up or down, in relation to commodity market prices as compared
to the Company's derivative instruments in place at such time.

                                       28
<PAGE>

ITEM 7.  FINANCIAL STATEMENTS

                           INDEPENDENT AUDITORS' REPORT

To the Board of Directors
Esenjay Exploration, Inc.

We have audited the accompanying consolidated balance sheets of Esenjay
Exploration, Inc. and subsidiaries (the "Company") as of December 31, 2000
and 1999, and the related consolidated statements of operations,
stockholders' equity and cash flows for the years then ended. 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 of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free from 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, such consolidated financial statements present fairly, in all
material respects, the consolidated financial position of the Company as of
December 31, 2000 and 1999, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.



Deloitte & Touche LLP
Houston, Texas

April 16, 2001

                                       29
<PAGE>

                               ESENJAY EXPLORATION, INC.
                              CONSOLIDATED BALANCE SHEETS

                                       ASSETS

<TABLE>
<CAPTION>
                                                                      DECEMBER 31,            DECEMBER 31,
                                                                         2000                     1999
                                                                     --------------          -------------
<S>                                                                  <C>                     <C>
Current assets:
     Cash and cash equivalents..................................     $   3,002,700           $   2,598,047
     Accounts receivable, net of allowance for doubtful
        accounts of  $445,872 and $519,137, respectively........        14,259,833               7,078,109
     Prepaid expenses and other.................................         2,183,093               3,940,133
     Receivables from affiliates................................           124,268                 363,027
                                                                     -------------           -------------
              Total current assets..............................        19,569,894              13,979,316

Property and equipment..........................................        81,977,022              80,120,781
Less accumulated depletion, depreciation
     and amortization...........................................       (40,087,050)            (25,937,472)
                                                                     -------------           -------------
                                                                        41,889,972              54,183,309

Other assets  ..................................................           903,208                 770,210
                                                                     -------------           -------------
              Total assets......................................     $  62,363,074           $  68,932,835
                                                                     =============           =============
</TABLE>




                                       30
<PAGE>

                            ESENJAY EXPLORATION, INC.
                           CONSOLIDATED BALANCE SHEETS

                      LIABILITIES AND STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                                    DECEMBER 31,     DECEMBER 31,
                                                                       2000              1999
                                                                    ------------     ------------
<S>                                                                 <C>              <C>
Current liabilities:
     Accounts payable ..........................................    $  6,450,723     $  8,838,629
     Accounts payable to affiliate .............................         269,835        2,083,913
     Revenue distribution payable ..............................       6,101,354        2,491,798
     Current portion of long-term debt .........................       6,750,000       11,013,162
     Accrued, deferred and other liabilities ...................       4,687,855        6,095,188
                                                                    ------------     ------------
              Total current liabilities ........................      24,259,767       30,522,690

Long-term debt .................................................      13,591,782        4,750,000
Non-recourse debt ..............................................              --          864,000
Accrued interest on non-recourse debt ..........................              --          463,395
                                                                    ------------     ------------
              Total liabilities ................................      37,851,549       36,600,085

Stockholders' equity:
     Convertible preferred stock $.01 par value;
        5,000,000 shares authorized; 356,999 shares issued and
        outstanding at December 31, 1999 .......................              --            3,570
     Common stock:
        Class A common stock, $.01 par value; 40,000,000
        shares authorized; and 18,958,477 and 18,837,699
        outstanding, respectively ..............................         189,585          188,377
     Additional paid-in capital ................................      84,699,705       84,987,704
     Stock subscription receivable .............................        (106,060)        (109,800)
     Accumulated deficit .......................................     (60,271,705)     (52,737,101)
                                                                    ------------     ------------
              Total stockholders' equity .......................      24,511,525       32,332,750
                                                                    ------------     ------------
              Total liabilities and stockholders' equity .......    $ 62,363,074     $ 68,932,835
                                                                    ============     ============
</TABLE>


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

                                       31
<PAGE>


                            ESENJAY EXPLORATION, INC.

                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                                 -----------------------------
                                                                     2000             1999
                                                                 ------------     ------------
<S>                                                              <C>              <C>
Revenues:
     Gas and oil revenues ...................................    $ 29,446,832     $  9,781,352
     Realized gain (loss) on commodity transactions .........      (4,842,372)         146,337
     Gain on sale of assets .................................       9,329,631        2,243,511
     Operating fees .........................................         454,016          344,539
     Other revenues .........................................         286,646           50,426
                                                                 ------------     ------------
              Total revenues ................................      34,674,753       12,566,165
                                                                 ------------     ------------
Costs and expenses:
     Lease operating expense ................................       1,172,590          752,861
     Production taxes .......................................       2,107,093          655,145
     Depletion, depreciation and amortization ...............       9,635,671        4,292,837
     Amortization of unproved properties ....................       5,176,100        7,546,000
     Impairment of oil and gas properties ...................       4,771,272          358,106
     Exploration costs-geological & geophysical .............       4,613,603        1,597,372
     Exploration costs-dry hole .............................       7,114,950          692,642
     Interest expense .......................................       1,361,533          871,501
     Delay rentals ..........................................         194,960          336,531
     General and administrative .............................       7,187,619        5,713,408
                                                                 ------------     ------------
              Total costs and expenses ......................      43,335,391       22,816,403
                                                                 ------------     ------------
Loss before provision for income taxes and extraordinary
  gain ......................................................      (8,660,638)     (10,250,238)
Benefit (provision) for income taxes ........................              --               --
                                                                 ------------     ------------
Net loss before extraordinary gain ..........................      (8,660,638)     (10,250,238)
Extraordinary gain ..........................................       1,126,034               --
                                                                 ------------     ------------
Net loss attributable to common stockholders ................    $ (7,534,604)    $(10,250,238)
                                                                 ============     ============

Net loss per share of common stock:
     Basic and diluted:
        Net loss before extraordinary gain attributable
              to common stockholders ........................    $      (0.46)    $      (0.62)
        Extraordinary gain ..................................            0.06               --
                                                                 ------------     ------------
        Net loss attributable to common shareholders ........    $      (0.40)    $      (0.62)
                                                                 ============     ============

Weighted average number of common shares outstanding ........      18,877,192       16,612,314
                                                                 ============     ============
</TABLE>

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

                                       32
<PAGE>

                            ESENJAY EXPLORATION, INC.

                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                    Preferred                    Class A
                                      Stock                    Common Shares          Additional       Stock
                            --------------------------    ------------------------     Paid-in      Subscription   Accumulated
                               Shares        Amount          Shares       Amount       Capital      Receivable      Deficit
                            -----------  -------------    -----------  ------------  ------------   ------------  -------------
<S>                         <C>          <C>              <C>          <C>           <C>            <C>           <C>
Balance,
 December 31, 1998 ......            --             --     15,784,834  $    157,849  $ 77,651,602             --   $(42,486,863)

Issuance of common
  stock for
  acquisitions, net .....            --             --      2,906,839        29,068     6,378,334             --             --
Issuance of
  preferred stock .......       356,999   $      3,570             --            --       683,653             --             --
Issuance of common
   stock ................            --             --         62,026           620       121,235             --             --
Issuance of common
  stock through
  subscriptions .........            --             --         84,000           840       152,880   $   (109,800)            --
  Net loss ..............            --             --             --            --            --             --    (10,250,238)
                           ------------   ------------   ------------  ------------  ------------   ------------   ------------
  Balance,
    December 31, 1999 ...       356,999          3,570     18,837,699       188,377    84,987,704       (109,800)   (52,737,101)

Issuance of warrants ....            --             --             --            --       110,000             --             --
Redemption of
  preferred stock .......      (356,999)        (3,570)            --            --      (683,655)            --             --
Issuance of common
  stock .................            --             --         88,778           888       216,516             --             --
 Payment of stock
     subscription
     receivable .........            --             --             --            --            --         73,200             --
 Issuance of common stock
  through subscriptions .            --             --         32,000           320        69,140        (69,460)            --
 Net loss ...............            --             --             --            --            --             --     (7,534,604)
                           ------------   ------------   ------------  ------------  ------------   ------------   ------------
Balance,
  December 31, 2000 .....            --   $         --     18,958,477  $    189,585  $ 84,699,705   $   (106,060)  $(60,271,705)
                           ============   ============   ============  ============  ============   ============   ============
</TABLE>

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

                                       33
<PAGE>

                            ESENJAY EXPLORATION, INC.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                                     Year Ended December 31,
                                                                             ----------------------------------------
                                                                                   2000                   1999
                                                                             -----------------       ----------------
<S>                                                                          <C>                     <C>
Cash flows from operating activities:
     Net loss ..........................................................     $  (7,534,604)          $ (10,250,238)
     Adjustments  to  reconcile  net  loss to net cash provided by
       (used in) operating activities:
          Depletion, depreciation and amortization .....................         9,635,671               4,292,837
          Amortization of unproven property.............................         5,176,100               7,546,000
          Impairment of oil and gas properties..........................         4,771,272                 358,106
          Exploration costs - dry hole..................................         7,114,950                 692,642
          Gain on sale of assets........................................        (9,329,631)             (2,243,511)
          Amortization of financing costs...............................               ---                 101,587
          Extraordinary gain............................................        (1,126,034)                    ---
     Changes in operating assets and liabilities:
          Trade and affiliate receivables...............................        (6,942,964)             (3,487,403)
          Prepaid expenses..............................................         1,757,040              (3,817,711)
          Other assets..................................................          (136,568)               (323,119)
          Trade and affiliate payables..................................        (4,201,984)                479,387
          Revenue distribution payable..................................         3,609,556                 495,707
          Accrued, deferred and other liabilities.......................        (1,407,333)              5,610,432
                                                                             -----------------       ----------------

          Net cash provided by (used in) operating activities...........         1,385,471                (545,284)
                                                                             -----------------       ----------------

Cash flows from investing activities:
     Capital expenditures - gas and oil properties......................       (19,254,789)            (19,478,942)
     Capital expenditures - other property and equipment................          (183,013)               (558,748)
     Proceeds from sale of assets.......................................        14,362,776              14,970,015
                                                                             -----------------       ----------------

        Net cash used in investing activities...........................        (5,075,026)             (5,067,675)
                                                                             -----------------       ----------------

Cash flows from financing activities:
     Proceeds from issuance of debt.....................................        20,341,782               8,920,000
     Repayments of long-term debt.......................................       (15,964,523)             (1,508,074)
     Preferred stock redeemed...........................................          (683,655)                    ---
     Proceeds from issuance of warrants.................................           110,000                     ---
     Net proceeds from issuance of common stock.........................           217,404                 152,880
     Payment of stock subscriptions receivables.........................            73,200                     ---
                                                                             -----------------       ----------------

        Net cash provided by financing activities.......................         4,094,208               7,564,806
                                                                             -----------------       ----------------

     Net increase in cash and cash equivalents..........................           404,653               1,951,847

Cash and cash equivalents at beginning of year..........................         2,598,047                 646,200
                                                                             -----------------       ----------------

Cash and cash equivalents at end of year................................     $   3,002,700           $   2,598,047
                                                                             =================       ================
</TABLE>

                                       34
<PAGE>

<TABLE>
<CAPTION>
                                                                                   Year Ended December 31,
                                                                           ----------------------------------------
                                                                                 2000                   1999
                                                                           -----------------       ----------------
<S>                                                                        <C>                     <C>
Supplemental disclosure of cash flow information:
     Cash paid for interest.............................................       $1,372,124            $   1,763,323
Supplemental disclosure of non-cash investing
     and financing activities:
        Sale of oil and gas properties in satisfaction
          of payable to affiliates......................................              ---            $   2,700,000
        Acquisition of assets...........................................              ---                8,333,853
        Proxy costs.....................................................              ---                  316,503
        Assumption of related liabilities...............................              ---                  923,252
        Issuance of common stock........................................       $   69,460                6,723,378
        Issuance of preferred stock.....................................              ---                  687,223
</TABLE>

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







                                       35
<PAGE>

                            ESENJAY EXPLORATION, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

         BASIS OF PRESENTATION - Esenjay Exploration, Inc.'s (the "Company")
primary business activities include gas and oil exploration, production and
sales, primarily along the Texas and Louisiana Gulf Coast areas of the United
States. The accompanying consolidated financial statements include the
accounts of the Company, and its subsidiaries. All significant intercompany
accounts and transactions have been eliminated upon consolidation.

         The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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 financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
these estimates.

         CASH EQUIVALENTS - The Company considers all investments with a
maturity of three months or less when purchased to be cash equivalents.

         GAS AND OIL PROPERTIES - The Company uses the successful efforts
method of accounting for gas and oil exploration and development costs. All
costs of acquired wells, productive exploratory wells, and development wells
are capitalized and depleted by the unit of production method based upon
estimated proved developed reserves. Exploratory dry hole costs, geological
and geophysical costs, and lease rentals on non-producing leases are expensed
as incurred. Gas and oil leasehold acquisition costs are capitalized. The
costs of multiple producing properties acquired in a single transaction are
allocated to individual producing properties based on estimates of gas and oil
reserves and future cash flows. Costs of unproved properties are transferred
to proved properties when reserves are proved. Gains or losses on sale of
leases and equipment are recorded in income as the sales are completed.
Remaining costs are depleted by the unit of production method based upon
estimated proved reserves. Valuation allowances are provided if the net
capitalized costs of gas and oil properties at the field level exceed their
realizable values based on expected future cash flows. Unproved properties are
periodically assessed for impairment and, if necessary, a loss is recognized.
This analysis resulted in $4,771,272 and $358,106 of impairment charges during
2000 and 1999, respectively.

         In addition, the $54,200,000 fair market value assigned to unproven
gas and oil exploration projects contributed by Esenjay Petroleum Corporation
("EPC") and Aspect Resources LLC ("Aspect") pursuant to certain acquisitions
of undeveloped exploration projects (the "Acquisitions") which closed on May
14, 1998 is, until such time as the book value of each such project is either
drilled and transferred to producing properties or is otherwise evaluated as
impaired, are being amortized on a straight-line basis over a period not to
exceed forty-eight months. Such amortization was $5,176,100 and $7,546,000
for the years ended December 31, 2000 and 1999, respectively. The balance in
this amortizing group of unproven properties was $5,334,700 and $13,392,100
at December 31, 2000 and 1999, respectively.

         OTHER PROPERTY AND EQUIPMENT - Other property and equipment is
carried at cost. The Company provides for depreciation of other property and
equipment using the straight-line method over the estimated useful lives of
the assets, which range from three to ten years.

         Upon sale or retirement of an asset, the cost of the asset disposed
of and the related accumulated depreciation are removed from the accounts,
and the resulting gain or loss is reflected in income.

         INCOME TAXES - The Company accounts for income taxes on an asset and
liability method which requires, among other things, the recognition of
deferred tax liabilities and assets for the tax effects of temporary
differences between the financial and tax bases of assets and liabilities,
operating loss carryforwards, and tax credit carryforwards.

                                       36
<PAGE>

         COMMODITY TRANSACTIONS - The Company attempts to minimize the price
risk of a portion of its future oil and gas production with commodity futures
contracts. Gains and losses on these contracts are recognized in the period
in which revenue from the related gas and oil production is recorded or when
the contracts are closed. To the extent that the quantities hedged under the
commodity transaction exceed current production, the Company recognizes gains
or losses on the overhedged amount. This policy was changed as of January 1,
2001. (See Note 2 - Recent Events)

         CAPITALIZED INTEREST - The Company capitalizes interest costs
incurred on exploration projects. Interest capitalized for the years ended
December 31, 2000 and 1999 was approximately $219,197 and $1,023,221,
respectively.

         GAS BALANCING - The Company records gas revenue based on the
entitlement method. Under this method, recognition of revenue is based on the
Company's pro-rata share of each well's production. During such time as the
Company's sales of gas exceed its pro-rata ownership in a well, a liability
is recorded, and conversely a receivable is recorded for wells in which the
Company's sales of gas are less than its pro-rata share. The Company's gas
balancing position at December 31, 2000 and 1999 was approximately 135,676
MCF or $245,719 and 114,721 MCF or $117,952 overproduced, respectively.

         EXPLORATION COSTS - The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. In
2000 and 1999, the Company expensed $4,613,603 and $1,597,372 in geological
and geophysical costs, respectively, and $7,114,950 and $692,642 in dry hole
costs, respectively. For purposes of reporting cash flows, the Company adds
back to operating activities all exploration costs which have been previously
capitalized, such as dry hole costs.

         FAIR VALUE OF FINANCIAL INSTRUMENTS - Statement of Financial
Accounting Standards No. 107. "Disclosures about Fair Value of Financial
Instruments" requires disclosure regarding the fair value of financial
instruments for which it is practical to estimate that value. The carrying
amount of cash and cash equivalents, accounts receivable and accounts
payable, approximates fair market value because of the short maturity of
those instruments. The fair value of the Company's long-term debt is
estimated to approximate carrying value based on the borrowing rates
currently available to the Company for bank loans with similar terms and
average maturities.

         The Company has interest rate and gas swap agreements that subject
it to off-balance sheet risk. These unrealized losses on these contracts are
based on market quotes. These unrealized losses are not recorded in the
consolidated financial statements to the extent the swaps qualify for hedge
accounting. This policy was changed as of January 1, 2001. (See Note 2 -
Recent Events)

         EARNINGS PER SHARE - Basic earnings per share has been computed by
dividing net income to common shareholders by the weighted average number of
common shares outstanding. Diluted earnings per share is calculated by
dividing net income to common shareholders by the weighted average number of
common shares outstanding plus dilutive potential common shares. For the
years ended December 31, 2000 and 1999 all potentially diluted securities are
anti-dilutive and therefore are not included in the earnings per share
calculation.

         The following table presents information necessary to calculate basic
and diluted earnings per share for the periods indicated:

<TABLE>
<CAPTION>
                                                                                         2000              1999
                                                                                     ------------     -------------
<S>                                                                                  <C>              <C>
 BASIC AND DILUTED EARNINGS PER SHARE
   Weighted average common shares outstanding ...................................      18,877,192       16,612,314
                                                                                     ============     ============
   Basic and diluted loss per share before extraordinary gain ...................    $      (0.46)    $      (0.62)
                                                                                     ============     ============
   Basic and diluted loss per share .............................................    $      (0.40)    $      (0.62)
                                                                                     ============     ============
EARNINGS FOR BASIC AND DILUTED COMPUTATION
   Net loss to common stockholders before extraordinary gain ....................    $ (8,660,638)    $(10,250,238)
   Extraordinary gain ...........................................................       1,126,034              ---
                                                                                     ------------     ------------
   Net loss to common shareholders (basic and
     diluted loss per share computation) ........................................    $ (7,534,604)    $(10,250,238)
                                                                                     ============     ============
</TABLE>

2.       RECENT EVENTS

         As of December 31, 2000, Tranche A of the Company's credit facility
with Deutsche Bank AG, New York Branch ("Deutsche Bank") was scheduled to mature
on January 24, 2001, at which time any remaining principal

                                       37
<PAGE>

balance would convert to a five-year monthly amortizing term loan. Effective
February 23, 2001, the maturity date of Tranche A was reset to January 25,
2002, at which time any remaining principal balance will convert into a
five-year monthly amortizing term loan. The effect of this change is reflected
as of December 31, 2000. On April 16, 2001 the available borrowing base
pursuant to Tranche A of the Deutsche Bank credit facility was increased to
$20,000,000. The borrowing base is scheduled to again be reviewed in the third
quarter of 2001.

         On January 25, 2001, the Company completed a restructuring of a
significant portion of its outstanding natural gas price hedges. The hedges
restructured covered 7,161 MMBtu/day of natural gas production in February
and March of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600
MMBtu/day for the third quarter of 2001, and 6,319 MMBtu/day for the fourth
quarter of 2001. All hedges were at $2.45 per MMBtu. These hedges were
restructured on January 25, 2001 for all periods beginning February 1, 2001,
and any rights or obligations of the Company pursuant to the previously
existing $2.45 hedges were cancelled. Pursuant to the restructured
agreements, the Company has subjected volumes of its Gulf Coast natural gas
production to a "collar" structure with a floor price of $3.25 per MMBtu and
a ceiling or cap price of $4.00 per MMBtu. Volumes committed to this
structure are 7,500 MMBtu per day in February and March of 2001, 7,900 MMBtu
per day in the second quarter of 2001, and 8,000 MMBtu per day in the third
and fourth quarter of 2001. In 2002, volumes committed are 8,500, 8,000,
7,500 and 7,000 MMBtu per day in the first through fourth quarter,
respectively. Finally, volumes committed to the collar structure include
4,500 MMBtu per day for calendar year 2003.

         In June 1998, Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) was
issued. The Company adopted SFAS 133 effective January 1, 2000. SFAS 133
requires that all derivatives be recognized as either assets or liabilities
and measured at fair value, and changes in the fair value of derivatives be
reported in current earnings, unless the derivative is designated and
effective as a hedge. If the intended use of the derivative is to hedge the
exposure to changes in the fair value of an asset, liability or firm
commitment, then changes in the fair value of the derivative instrument will
generally be offset in the income statement by the change in the hedged
item's fair value. However, if the intended use of the derivative is to hedge
the exposure to variability in expected future cash flows, then changes in
the fair value of the derivative instrument will generally be reported in
Other Comprehensive Income (OCI). The gains and losses on the derivative
instrument that are reported in OCI will be reclassified to earnings in the
periods in which earnings are impacted by the hedged item.

         In accordance with the transition provisions of SFAS 133 on January
1, 2001, the Company recorded a cumulative effect type adjustment of
($14,909,492) in OCI to recognize the fair value of all derivatives that are
designated as cash-flow hedges. This adjustment will change from period to
period, either up or down, in relation to commodity market prices as compared
to the Company's derivative instrument in place at such time.

3.       STOCKHOLDERS' EQUITY:

         In 2000 and 1999 the Company issued 120,778 and 3,052,865 additional
shares of common stock, respectively.

         On May 12, 1999, the Company announced that on May 11, 1999 it had
signed a Plan and Agreement of Merger with 3DX Technologies Inc. ("3DX")
which provided for the merger of 3DX into the Company (the "Acquisition").
The shareholders of both companies approved the transaction at duly called
shareholders meetings on September 23, 1999 and the merger was consummated
the same day. The purchase price of the Acquisition was approximately $7.4
million, of which $6.7 million was in the Company's common stock and $0.7
million was in the Company's preferred stock.

         The terms of the merger provided for 3DX shareholders to receive, at
their election, either (i) the issuance of one share of Esenjay common stock
for 3.25 shares of 3DX common stock; or (ii) the issuance of a new Esenjay
convertible preferred stock at a ratio of one share of Esenjay convertible
preferred stock for each 2.75 shares of 3DX common stock. Approximately 91%
of the 3DX common shares converted into Esenjay common stock and
approximately 9% were converted into Esenjay convertible preferred stock. As
a result, Esenjay issued 2,906,778 new shares of common stock and 356,999
shares of convertible preferred stock. The convertible preferred stock could
be redeemed at Esenjay's sole option until September 23, 2000 at $1.925 per
share. On September 23, 2000, the Company redeemed all 356,999 outstanding
shares of the convertible

                                       38
<PAGE>

preferred stock for $1.925 per share.

         In May of 1999, seven directors of the Company each subscribed for
the purchase of 12,000 shares of common stock of the Company for an aggregate
total of 84,000 shares. The shares were at a price of $1.83 per share payable
one-third upon subscription, one-third in May of 2000 and one-third in May of
2001. Shares were delivered in 2000. In June of 2000, one director of the
Company subscribed to purchase 12,000 shares of Common Stock of the Company at
$1.83 per share payable one-third upon subscription, one-third on or before
May 15, 2001 and one-third on or before May 15, 2002. At December 31, 2000,
the Company had a common stock subscription receivable of $58,560 outstanding
related to these shares.

         In 2000 the Company issued a total of 47,252 and 61,547 shares of
common stock pursuant to various employee options which were exercised during
the year and the Company's match of shares purchased in the Company's 401K
plan, respectively.

         WARRANTS - Since December 31, 1997, the Company has had Series B
Warrants, which entitles the holder to purchase one share of common stock for
$12.15 until August 8, 2001. Each Series B Warrant is redeemable by the
Company with the prior consent of the underwriter at a price of $0.06 per
Series B Warrant, at any time after the Series B Warrants become exercisable,
upon not less than 30 days notice, if the last sale price of the common stock
has been at least 200% of the then exercise price of the Series B Warrants
for the 20 consecutive trading days ending on the third day prior to the date
on which the notice of redemption is given.

         In January of 1996, the Company issued warrants to purchase 83,334
shares of common stock, 41,667 of which shares were at an exercise price of
$21.735 per share and 41,667 of which shares were at an exercise price of
$12.00 per share. The warrants exercisable at $21.735 expire January 3, 2001
and the warrants exercisable at $12.00 per share expire January 12, 2001.

         In the first quarter of 2000, the Company issued warrants in
connection with a financing transaction to purchase 250,000 shares of the
Company's common stock at an exercise price of $1.50 per share. The warrants
expire January 25, 2005. The fair value of these warrants were recorded in the
amount of $110,000.

         EMPLOYEE OPTION PLANS - The Company has option plans for employees
and directors that authorize the issuance of up to 3,000,000 options to
purchase one share of common stock. Options to purchase 2,497,168 shares of
common stock at prices ranging from $1.83 to $3.86 are currently outstanding.

         Under the plans, the Board may grant options to officers and other
employees. Each option shall consist of an option to purchase one share of
common stock at an exercise price that shall be at least the fair market
value of the common stock on the date of the grant of the option. However,
the Board may authorize vesting options as it deems necessary. Unless
otherwise so designated, the options shall be exercisable at a rate of 33
1/3% in the year following the effective date of the grant, and 33 1/3% each
of the two years thereafter. The Option holder's right is cumulative. Unless
otherwise designated by the Board, if the employment of the Option holder is
terminated for any reason, all unexercised Options shall terminate, be
forfeited and shall lapse within three months thereafter. The options have a
maximum life of ten years from the date of issuance.

         The following table summarizes activity under the Company's stock
option plans for the years ended December 31, 2000 and 1999.

                                       39
<PAGE>

<TABLE>
<CAPTION>
                                                                                   EMPLOYEE OPTION PLANS
                                                                    -----------------------------------------------------
                                                                              2000                       1999
                                                                    -------------------------  --------------------------
                                                                                    WEIGHTED                  WEIGHTED
                                                                                    AVERAGE                    AVERAGE
                                                                                    EXERCISE                  EXERCISE
                                                                       SHARES        PRICE        SHARES        PRICE
                                                                    ------------  -----------  -----------  -------------
<S>                                                                 <C>             <C>          <C>          <C>
          Outstanding at beginning of year.........................    1,259,667   $     2.42       94,001     $     3.92
          Granted..................................................    1,463,000         2.44    1,169,000           2.38
          Exercised................................................      (66,499)        2.38
          Forfeited................................................     (159,000)        2.38       (3,334)          7.68
                                                                    ------------  -----------  -----------  -------------
          Outstanding at end of year...............................    2,497,168   $     2.44    1,259,667     $     2.42
                                                                    ============  ===========  ===========  =============
          Weighted average fair value of
             options granted during the year.......................                $     1.51                  $     1.34
                                                                                  ===========               =============
</TABLE>

Options outstanding at December 31, 2000 consisted of the following:

<TABLE>
<CAPTION>
                                                                                     EXERCISABLE OPTIONS
                                                                             ---------------------------------
        RANGE OF                        WEIGHTED           WEIGHTED                              WEIGHTED
    EXERCISE PRICES    NUMBER OF    AVERAGE EXERCISE   AVERAGE REMAINING      NUMBER OF      AVERAGE EXERCISE
       PER SHARE        OPTIONS     PRICE PER SHARE    CONTRACTUAL LIFE        OPTIONS        PRICE PER SHARE
    ----------------- -----------  ----------------- --------------------    ------------   ------------------
<S>                   <C>          <C>               <C>                     <C>            <C>
     $1.83 - $3.86     2,497,168         $2.44          7.9 - 9.8 years        2,139,205           $2.41
</TABLE>

         The Company has adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation". Accordingly, no compensation cost has been recognized for the
stock option plans. Had compensation cost for the Company's stock option
plans been determined based on fair value at the grant date for awards in
2000 and 1999 consistent with the provisions of SFAS No. 123, the Company's
pro forma net loss applicable to common stockholders and net loss per common
and common equivalent share would have been as indicated below:

<TABLE>
<CAPTION>
                                                                                                   2000              1999
                                                                                                -------------   ---------------
<S>                                                                                             <C>             <C>
          Net loss attributable to common stockholders-as reported...........................    $(7,534,604)    $(10,250,238)
          Net loss attributable to common stockholders-pro forma.............................    $(8,531,852)    $(11,247,486)
          Net loss per common share-as reported..............................................         $(0.40)          $(0.62)
          Net loss per common share-pro forma................................................         $(0.45)          $(0.68)
</TABLE>

         The fair value of each option grant is estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions: no dividends; expected volatility of 81.61% and
80.99% in 2000 and 1999; risk-free interest rate of 5.95% and 5.625% in 2000
and 1999; and expected lives of 10 years.

4.       SALE OF GAS AND OIL ASSETS AND SEISMIC DATA:

         The Company sold various interests in a number of different
projects, prospects and wells during 2000 and 1999. These sales resulted in
an aggregate gain of approximately $9,329,631 in 2000 and $2,243,511 in 1999.

                                       40
<PAGE>

5.       LONG-TERM DEBT:  (SEE NOTE 2)

         Long-term debt consists of the following:

<TABLE>
<CAPTION>
                                                                                             DECEMBER 31,
                                                                                    --------------------------------
                                                                                        2000              1999
                                                                                    --------------    --------------
<S>                                                                                 <C>               <C>
Non-recourse loan retired in 2000.................................................           ---      $    864,000
Note payable paid in 2000.........................................................           ---           100,000
Loan with Deutsche Bank AG, New York Branch ("Deutsche Bank"), in two Tranches:
   Tranche A is a revolving credit facility which terminates January 24, 2001,
   thereafter converting the unpaid balance into a five year term loan requiring
   monthly principal and interest payments; Tranche B is payable as to interest
   only until April 30, 2001, at which time quarterly payments of $2,250,000
   plus interest are required until the loan is amortized. Both loans are at a
   varied interest rate utilizing, at the Company's election, either Deutsche
   Bank's Alternative Reference Rate or the Interbank rate plus 2% for both
   Tranche A and Tranche B. The loan is secured by a mortgage on most
   properties currently owned by the Company...................................      $20,341,782               ---
Loan with Bank of America NT&SA was repaid with a portion of the proceeds from
    financing provided by Deutsche Bank...........................................           ---         8,523,162
Loan with Duke Energy Field Services, Inc. was repaid with a portion of the
    proceeds from financing provided by Deutsche Bank.............................           ---         7,140,000
                                                                                    --------------    --------------
                                                                                      20,341,782        16,627,162
Less current portion..............................................................     6,750,000        11,013,162
                                                                                    --------------    --------------
                                                                                     $13,591,782       $ 5,614,000
                                                                                    ==============    ==============
</TABLE>

         Maturities of long-term debt are as follows:

<TABLE>
<CAPTION>
YEAR                                                                                    AT DECEMBER 31,
                                                                                        ---------------
                                                                                             2000(1)
                                                                                             ------
<S>                                                                                     <C>
2001....................................................................                    $ 6,750,000
2002....................................................................                      6,219,623
2003....................................................................                      2,268,356
2004....................................................................                      2,268,356
2005....................................................................                      2,268,356
2006....................................................................                        567,091
</TABLE>

(1)      Amortization of amounts advanced pursuant to Tranche A of the Deutsche
         Bank credit facility was reset in 2001 and, as such, no Tranche A
         amounts are currently scheduled for amortization in 2001. (See Note 2
         for information regarding maturities under this facility over the next
         5 years.)

         On January 25, 2000, the Company closed a credit facility with
Deutsche Bank AG, New York branch. This facility provides for Deutsche Bank to
loan up to $29,000,000 to be available in two tranches. Tranche A is
structured in the amount of $20,000,000, with $16,000,000 established as the
current available borrowing base, and Tranche B is fully drawn in the amount
of $9,000,000. Under the terms and conditions of this facility, the facilities
existing at December 31, 1999 with Duke Energy Financial Services, Inc. and
Bank of America, NT&SA, were paid in full utilizing approximately $15,800,000
of the available proceeds from Deutsche Bank. As of December 31, 2000, Tranche
A was scheduled to mature on January 24, 2001, at which time any remaining
unpaid principal would convert to a five-year monthly amortizing term loan.
This was reset in February 2001 to mature on January 25, 2002 and the change
is incorporated in the above schedule. The Tranche B loan is payable interest
only through April 30, 2001 after which date the amount available decreases by
25% per quarter beginning April 30, 2001 with a final maturity in January of
2006. In addition, the Company must remain in compliance with certain
covenants required by Deutsche Bank, including a redetermination of the
borrowing base every six months. The company also is required to assign an
overriding royalty interest to Deutsche Bank for those wells logged prior to
the later of the maturity date of Tranche B or the Tranche A termination date
or the date the Tranche B Loan is repaid. The

                                       41
<PAGE>

Company may repurchase this overriding royalty interest prior to April 30,
2002, if all Tranche B loans are repaid in full.

         The amount available pursuant to Tranche A has been increased since
December 31, 2000. (See Note 2 - Recent Events.)

6.       INCOME TAXES:

         Deferred tax assets and liabilities are as follows:

<TABLE>
<CAPTION>
                                                                                   AT DECEMBER 31,
                                                                         ----------------------------------
                                                                               2000               1999
                                                                         ---------------    ---------------
<S>                                                                      <C>                <C>
Net operating tax loss carry forward.................................    $    18,176,646    $    17,590,565
Property and equipment...............................................          3,836,490          2,166,546
Valuation allowance..................................................        (22,013,136)       (19,757,111)
                                                                         ----------------   ----------------
   Net deferred tax asset (liability)................................    $           ---    $           ---
                                                                         ================   ================
</TABLE>

         The Company has recorded a deferred tax valuation allowance since,
based on an assessment of all available historical evidence, it is more likely
than not that future taxable income will not be sufficient to realize the tax
benefit. The Company and its subsidiaries have net operating loss
carryforwards ("NOLs") at December 31, 2000, of approximately $51,900,000
which may be used to offset future taxable income. The operating loss
carryforwards expire in the tax years 2006 through 2020.

         The ability of the Company to utilize NOLs and tax credit
carryforwards to reduce future federal income taxes of the Company may be
subject to various limitations under the Internal Revenue Code of 1986, as
amended (the "Code"). One such limitation is contained in Section 382 of the
Code which imposes an annual limitation on the amount of a corporation's
taxable income that can be offset by those carryforwards in the event of a
substantial change in ownership as defined in Section 382 ("Ownership
Change"). In general, Ownership Change occurs if during a specified
three-year period there are capital stock transactions, which result in an
aggregate change of more than 50% in the beneficial ownership of the stock of
the Company. The Company incurred such an Ownership Change in 1998.

7.       RELATED PARTY TRANSACTIONS:

         On December 31, 2000 and 1999, the Company had accounts receivable
from employees and affiliates totaling net amounts of $124,267 and $553,950,
respectively. The December 31, 2000 balance includes net accounts payable due
to Aspect in the amount of $122,506. The December 31, 2000 and 1999 balance
includes net accounts receivable due from EPC in the amount of $101,199 and
$190,923, respectively. At December 31, 1999, the company had a net account
payable due to Aspect in the amount of $2,083,913.

8.       COMMITMENTS AND CONTINGENCIES:

         The Company leases office space under lease agreements, which are
classified as operating leases. Lease expense under these agreements was
$300,290 in 2000 and $291,169 in 1999. A summary of future minimum rentals on
these non-cancelable operating leases is as follows:

<TABLE>
<CAPTION>
                                                                               AT DECEMBER 31,
YEAR                                                                                 2000
----                                                                                 ----
<S>                                                                            <C>
2001....................................................................           $248,445
2002....................................................................            168,137
2003....................................................................             84,068
</TABLE>

                                       42
<PAGE>

         The Company markets its natural gas through monthly spot sales.
Because sales made under spot sales contracts result in fluctuating revenues
to the Company depending upon the market price of gas, the Company may enter
into various hedging agreements to minimize the fluctuations and the effect
of price declines or swings.

         During January 1999, the Company completed performance on a 1996
swap agreement on approximately 1,040 MMBtu per day of Mid-Continent natural
gas production for $1.566 per MMBtu for the period beginning April 1, 1996
and ending January 31, 1999. In October of 1998, the Company entered into two
swap agreements, one for 4,000 MMBtu per day of its Gulf Coast natural gas
production for $2.14 per MMBtu for the period beginning November 1998 and
ending in October 1999, and the second one for 700 MMBtu per day of its Gulf
Coast natural gas production for $2.13 per MMBtu for the period beginning
November 1998 and ending in October 1999. Both of these swap agreements were
supplemented in December 1998 when the Company entered into additional swap
agreements, one of which was for 4,000 MMBtu per day of its Gulf Coast
natural gas production for $2.07 per MMBtu for the period beginning November
1999 and ending in October 2000, and the second one was for 700 MMBtu per day
of its Gulf Coast natural gas production for $2.07 per MMBtu for the period
beginning November 1999 and ending in October 2000. In September of 1999, the
Company entered into a series of swap agreements on additional natural gas
and oil production. It hedged 5,000 MMBtu per day of natural gas for the
months of September through December 1999 at a price of $3.055 per MMBtu, it
hedged 3,000 MMBtu per day for the period of January through March of 2000,
2,400 MMBtu per day for the period April through June of 2000, and 1,700
MMBtu per day for the period of July through September of 2000, the latter
three hedges of which were all at a price of $2.68 per MMBtu. In addition,
the Company entered into a "collar" hedge arrangement on certain of its oil
production. This oil hedge was for a quantity equal to 300 barrels of oil per
day in the fourth quarter of 1999, 280 barrels of oil per day in the first
quarter of 2000, 256 barrels of oil per day in the second quarter of 2000,
and 237 barrels of oil per day in the third quarter of 2000, all of which
transactions were structured with an $18.00 floor price and a $20.40 cap
price.

         In February of 2000, in conjunction with its financing with Deutsche
Bank, the Company restructured all existing natural gas hedges with an
affiliate of Deutsche Bank. Pursuant to these hedges, the Company had 9,381
MMBtu/day of net production hedged in March, 2000, 9,031 MMBtu/day hedged for
the second quarter of 2000, 8,646 MMBtu/day for the third quarter of 2000,
8,278 MMBtu/day for the fourth quarter of 2000, 7,161 MMBtu/day for the first
quarter of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600
MMBtu/day for the third quarter of 2001, and 6,319 MMBtu/day for the fourth
quarter of 2001. All hedges were at $2.45 per MMBtu. Concurrent with the
restructuring of the hedges, the Company was relieved of any liability or
rights pursuant to all previously existing natural gas hedges. An existing
"collar" hedge arrangement on 280 barrels of oil per day in the first quarter
of 2000, and 256 and 237 barrels of oil per day in the second and third
quarters of 2000, respectively, was transferred to the Deutsche Bank
affiliate at the existing $18.00 floor price and $20.40 cap price. These
positions were supplemented with oil hedges at $21.03 per barrel on volumes
of 238 barrels of oil per day in the fourth quarter of 2000 and 175, 168,
161, and 154 barrels of oil per day in the first through fourth quarters of
2001, respectively. In the third quarter of 2000, the Company hedged an
additional 5,000 MMBtu/day of natural gas. The hedge prices were $4.70 per
MMBtu for the months of September through December 2000, and $4.01 per MMBtu
for the months of January through December 2001.

         In January of 2001 certain of the above hedge instruments were
restructured. (See Note 2 - Recent Events.)

9.    ACQUISITIONS:

         On May 12, 1999, the Company announced that on May 11, 1999 it had
signed a Plan and Agreement of Merger with 3DX Technologies Inc. ("3DX")
which provided for the merger of 3DX into the Company (the "3DX
Acquisition"). The shareholders of both companies approved the transaction at
duly called shareholders meetings on September 23, 1999 and the merger was
consummated the same day. The purchase price of the 3DX Acquisition was
approximately $7.4 million, of which $6.7 million was in the Company's common
stock and $0.7 million was in the Company's preferred stock. The 3DX
Acquisition included, at fair value, current assets of $2.5 million, property
and equipment of $5.8 million, other assets of $0.1 million and liabilities
of $0.9 million.

         3DX Technologies Inc. was a Houston-based exploration and production
company whose strategic business focus was the utilization of 3-D seismic
imaging and other advanced technologies in the search for natural gas and oil
principally in the onshore gulf coast of the United States. As a result of
the merger, the Company employed four

                                       43
<PAGE>

members of the reservoir engineering and geophysical staff of 3DX, plus one
support person, increased its gas and oil reserves, its monthly gas and oil
revenues, and expanded its ownership of 3D seismic data and projects.

         The acquisitions have been accounted for using the purchase method
of accounting and, accordingly, the purchase price has been allocated to the
assets and liabilities acquired based on fair value at the date of
acquisition. The operating results of the acquisitions have been included in
the Company's consolidated financial statements from their respective dates
of acquisition. The following unaudited pro forma information presents a
summary of the consolidated results of operations for the year ended December
31, 1999 as if the acquisitions had occurred prior to January 1, 1999.

<TABLE>
<CAPTION>
                                                                                  YEAR ENDED
                                                                                 DECEMBER 31,
                                                                                     1999
                                                                               -----------------
<S>                                                                            <C>
        Revenues.....................................................          $      14,176,091
        Total costs and expenses.....................................                 28,393,836
                                                                               -----------------
        Net loss.....................................................          $     (14,217,745)
                                                                               =================
        Basic and diluted loss per share.............................          $           (0.73)
                                                                               =================
        Weighted average number of common shares
              Outstanding............................................                 19,518,839
                                                                               =================
</TABLE>

10.      PROPERTY AND EQUIPMENT:

<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31,
                                                                             ---------------------------------
                                                                                    2000              1999
                                                                             ---------------    --------------
<S>                                                                          <C>                <C>
        Gas and oil properties, at cost, successful
             efforts method of accounting:
                 Proved...........................................             $ 29,934,906       $ 30,586,079
                 Unproved, subject to amortization  ..............                5,334,700         13,392,100
                 Unproved, not subject to amortization............               44,689,074         34,180,470
                    Total gas and oil properties..................               79,958,680         78,158,649
        Other property and equipment..............................                2,018,342          1,962,132
                                                                               ------------       ------------
        Total oil and gas properties and equipment................               81,977,022         80,120,781
        Less accumulated depletion, depreciation
             and amortization.....................................              (40,087,050)       (25,937,472)
                                                                               ------------       ------------
        Total property and equipment, net.........................             $ 41,889,972       $ 54,183,309
                                                                               ============       ============
</TABLE>

11.      SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED):

         The Company's proved gas and oil reserves are located in the United
States. Proved reserves are those quantities of natural gas and crude oil
which, upon analysis of geological and engineering data, demonstrate with
reasonable certainty to be recoverable in the future from known gas and oil
reservoirs under existing economic and operating conditions (i.e. price and
costs as of the date the estimate is made). Proved developed (producing and
non-producing) reserves are those proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating
methods. Proved undeveloped gas and oil reserves are 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.

         Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units can be claimed only
where it can be demonstrated with certainty that there is continuity of
production from the existing productive formation.

                                       44
<PAGE>

         FINANCIAL DATA

         The Company's gas and oil producing activities represent substantially
all of the business activities of the Company. The following costs include all
such costs incurred during each period, except for depreciation and amortization
of costs capitalized:

COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                           --------------------------
                                                                              2000            1999
                                                                           -----------    -----------
<S>                                                                        <C>            <C>
Acquisition of properties:
   Proved..............................................................    $      ---     $   848,505
   Unproved............................................................      4,525,278      5,214,982
Exploration costs......................................................     19,491,881     11,577,425
Development costs......................................................        916,168        859,349
                                                                           -----------    -----------
      Total costs incurred.............................................    $24,933,327    $18,500,261
                                                                           ===========    ===========
</TABLE>

CAPITALIZED COSTS:

<TABLE>
<CAPTION>
                                                                                           AT DECEMBER 31,
                                                                                    -----------------------------
                                                                                        2000             1999
                                                                                    ------------     ------------
<S>                                                                                 <C>              <C>
Proved..........................................................................    $ 29,934,906     $ 30,586,079
Unproved properties, subject to amortization....................................       5,334,700       13,392,100
Unproved properties, not subject to amortization................................      44,689,074       34,180,470
Less accumulated amortization...................................................     (38,806,340)     (24,828,022)
                                                                                    ------------     ------------
      Net capitalized costs.....................................................     $41,152,340     $ 53,330,627
                                                                                    ============     ============
</TABLE>

ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:

<TABLE>
<CAPTION>
                                                                                        CRUDE OIL, CONDENSATE AND
                                                                                           NATURAL GAS LIQUIDS
                                                             NATURAL GAS (MCF)                  (BARRELS)
                                                    ----------------------------------  --------------------------
                                                         YEARS ENDED DECEMBER 31,        YEARS ENDED DECEMBER 31,
                                                    ----------------------------------  --------------------------
                                                          2000              1999            2000          1999
                                                    ---------------    ---------------  ------------  ------------
<S>                                                 <C>                <C>              <C>           <C>
Proved developed and undeveloped reserves:
   Beginning of period.............................     18,793,038         11,929,667       372,795       100,195
   Purchases of minerals-in-place..................            ---            291,055           ---         4,802
   Sales of minerals-in-place......................     (3,334,327)               ---       (10,653)          ---
   Revisions of previous estimates.................     (5,451,343)        (6,027,430)     (131,569)      (45,872)
   Extensions, discoveries and other additions.....     16,929,105         15,981,338       387,817       414,229
   Production......................................     (5,860,195)        (3,381,592)     (163,892)     (100,559)
                                                    ---------------    ---------------  ------------  ------------
   End of period...................................     21,076,278         18,793,038_      454,498       372,795_
                                                    ==============     ===============  ===========   ============
Proved developed reserves:
   Beginning of period.............................     17,481,248          6,864,564       371,368        59,085
   End of period...................................     16,198,327         17,481,248       305,842       371,368
</TABLE>

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:

         The standardized measure of discounted future net cash flows is
based on criteria established by Financial Accounting Standards Board
Statement No. 69, "Accounting for Oil and Gas Producing Activities" and is
not intended to be a "best estimate" of the fair value of the Company's oil
and gas properties. For this to be the case, forecasts of future economic
conditions, varying price and cost estimates, varying discount rates and
consideration of other than proved reserves (i.e., probable reserves) would
have to be incorporated into the valuations.

                                       45
<PAGE>

         Future net cash inflows are based on the future production of proved
reserves of natural gas, natural gas liquids, crude oil and condensate as
estimated by petroleum engineers by applying current prices of gas and oil
(with consideration of price changes only to the extent fixed and
determinable and with consideration of the timing of gas sales under existing
contracts or spot market sales) to estimated future production of proved
reserves. Year end prices used in determining future cash inflows averaged for
natural gas and oil for the periods ended December 31, 2000 and 1999 were as
follows: 2000 - $10.44 per Mcf of natural gas, $28.73 per barrel of oil; 1999
- $2.30 per Mcf of natural gas, $22.20 per barrel of oil, respectively.
Future net cash flows are then calculated by reducing such estimated cash
inflows by the estimated future expenditures (based on current costs) to be
incurred in developing and producing the proved reserves and by the estimated
future income taxes. Estimated future income taxes are computed by applying
the appropriate year-end tax rate to the future pretax net cash flows
relating to the Company's estimated proved oil and gas reserves. The
estimated future income taxes give effect to permanent differences and tax
credits and allowances.

         The following table sets forth the Company's estimated standardized
measure of discounted future net cash flows:

<TABLE>
<CAPTION>
                                                                                      YEAR ENDED DECEMBER 31,
                                                                                 --------------------------------
                                                                                       2000              1999
                                                                                 --------------      ------------
<S>                                                                              <C>                 <C>
Future cash inflows.............................................................   $233,139,437       $49,970,700
Future development and production costs.........................................    (33,404,090)      (10,635,400)
Future income tax expenses......................................................            ---               ---
                                                                                 --------------      ------------
Future net cash flows...........................................................    199,735,347        39,335,300
Discount........................................................................    (38,189,947)       (6,822,200)
                                                                                 ---------------       ----------
Standardized measure of discounted future net cash flows........................    161,545,400       $32,513,100
                                                                                 ==============      ============
</TABLE>

         The following table sets forth changes in the standardized measure of
discounted future net cash flows:

<TABLE>
<CAPTION>
                                                                                      YEAR ENDED DECEMBER 31,
                                                                                -----------------------------------
                                                                                     2000                1999
                                                                                -----------------   ---------------
<S>                                                                              <C>                 <C>
Standardized measure of discounted future cash flows-beginning of period.......     $ 32,513,100       $12,520,021
Sales of oil and gas produced, net of operating expenses.......................      (26,505,466)       (9,037,645)
Purchases of minerals in place.................................................              ---           817,070
Net changes in sales prices and production costs...............................       45,131,636         1,067,500
Extensions, discoveries and improved recovery, less related costs..............      116,249,984        47,838,148
Change in future development costs.............................................        3,745,484         1,351,700
Previously estimated development costs incurred during the year................       (1,051,300)       (9,353,624)
Revisions of previous quantity estimates.......................................      (12,252,353)      (14,486,234)
Accretion of discount..........................................................        7,189,087         2,212,137
Net change of income taxes.....................................................              ---               ---
Sales of minerals-in-place.....................................................       (3,077,823)              ---
Changes in production rates (timing) and other.................................         (396,949)         (415,973)
                                                                                -----------------   ---------------

Standardized measure of discounted future cash flows-end of period.............     $161,545,400       $32,513,100
                                                                                ================    ==============
</TABLE>

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

         Not Applicable.

                                       46
<PAGE>

                                    PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT

         The following table sets forth certain information regarding the
Company's directors and executive officers.

<TABLE>
<CAPTION>
NAME                                                    AGE   POSITION
----                                                    ---   --------
<S>                                                     <C>   <C>
David W. Berry(1)(6).................................    51   Chairman of the Board
Alex M. Cranberg(1)(2)(4)............................    46   Vice Chairman of the Board
Michael E. Johnson(1)(4).............................    53   Director, President and Chief Executive Officer
Alex B. Campbell(3)(6)...............................    43   Director
William D. Dodge, III(2)(5)..........................    48   Director
Jack P. Randall(1)(3)(4).............................    51   Director
Hobart A. Smith(2)(3)(5).............................    64   Director
Jeffrey B. Pollicoff(6)..............................    48   Director
David B. Christofferson..............................    52   Senior Vice President, Secretary and General Counsel
</TABLE>
-----------
(1)      Member of the Executive Committee.
(2)      Member of the Audit Committee.
(3)      Member of the Compensation Committee.
(4)      Director whose term expires in 2003.
(5)      Director whose term expires in 2001
(6)      Director whose term expires in 2002

         DAVID W. BERRY served as President of the Company since the
incorporation of its predecessor in August 1988 and until May 14, 1998, and
has served as Chairman of the Board of Directors since 1991. In 1978, he
formed Berry Petroleum Corporation, which was a regional natural gas and oil
exploration company. In 1976 he co-founded Vulcan Energy Corporation, a
Tulsa, Oklahoma based exploration and production company. Mr. Berry has
served as the State Finance Chairman of the Oklahoma State Republican Party,
as a Trustee for the Oklahoma Museum of Art and on the United States
Senatorial Trust Committee. Mr. Berry is a member of the Independent
Petroleum Association of America.

         ALEX M. CRANBERG has been a director of the Company since May 14,
1998. He has been President of Aspect Management Corporation, the manager of
Aspect, since its inception in 1993. He joined Houston Oil and Minerals Corp.
in 1977 where he served in various engineering and financial roles. He has
managed the oil and gas portfolio of General Atlantic Partners, a private
investment firm, since 1981. He is on the Board of Directors of Brigham
Exploration, Inc., a public company, and Westport Oil and Gas, Inc., a public
exploration and production company active in the Rocky Mountain and Gulf
Coast Regions. He received a BS in petroleum engineering from the University
of Texas and an MBA from Stanford University.

         MICHAEL E. JOHNSON has been a director, President and Chief
Executive Officer of the Company since May 14, 1998. He was President of EPC
from 1978 until joining the Company. Mr. Johnson was an operations engineer
for Atlantic Richfield Co. from 1971 to 1976 and worked for Tana Oil and Gas
before co-founding EPC, where he has managed all exploration activities,
coordinated outside technical support and raised capital from industry
partners. He received a BS degree in mechanical engineering from the
University of Southwestern Louisiana.

         ALEX B. CAMPBELL has been a director of the Company since May 14,
1998. He has been an officer of Aspect Management Corporation since August
1996 and is currently an Executive Vice President responsible for land and
corporate development and legal issues. He served as landman for Grynberg
Petroleum and TXO Production Corp. from 1980 to 1984, focusing on the Rocky
Mountain Region, then as division landman for Lario Oil & Gas Company from
1984 to 1996, where he was responsible for administration, prospect
marketing, contract lease negotiation, exploration permitting, surface owner
negotiations and property acquisition negotiation and due diligence. He has a
BA in business/pre-law from Colorado State University, and an MBA from
Colorado State University.

         WILLIAM D. DODGE, III has been a director of the Company since May
14, 1998. He is currently a partner at Duran, Dodge & Associates, a Corpus
Christi insurance agency. He was Regional President of Pacific Southwest
Bank, Corpus Christi, Texas from 1995 until 2001. He was active in banking
since 1977, including serving as President of The Bank of Robstown, Texas
from 1982 until 1995. He also serves in a number of civic roles, including as
Chairman of the Port of Corpus Christi Authority, and serving on the Board of
Directors of Columbia Northwest

                                       47
<PAGE>

Hospital. Mr. Dodge is a member of the Editorial Review Board SAM Advanced
Management Journal at the Texas A&M University-Corpus Christi College of
Business. He received a BA degree from the University of Texas at Austin and
attended the Southwestern Graduate School of Banking, Southern Methodist
University.

         JACK P. RANDALL has been a director of the Company since May 14,
1998. He is co-founder and President of Houston-based Randall & Dewey, Inc.,
a full-service transaction advisory firm focusing solely on upstream oil and
gas mergers, acquisitions, divestments, trades and alliances. Its clients
include a cross section of companies ranging from the major oil companies to
small private independents. Prior to co-founding Randall & Dewey with Ken
Dewey, Mr. Randall was with Amoco Production Company for 15 years. He held
his last position, Manager of Acquisitions and Divestments, for seven years.
Mr. Randall is a graduate of The University of Texas (Austin) with a BS in
Engineering (1972) and an MS in Engineering (1975). He is a member of the
Board of Directors of Cross Timbers Oil Company and Esenjay Exploration,
Inc.; the Engineering Foundation Advisory Committee at the University of
Texas as well as Chairman of the Petroleum Engineering Visiting Committee.
Mr. Randall is also on the Board of Directors of the Sam Houston Council of
the Boy Scouts of America as well as District Chairman of the Rising Star
District; the M.D. Anderson Cancer Center Board of Visitors as well as being
a member of the SPE, API and IPAA.

         HOBART A. SMITH has been a director of the Company since May 14,
1998. He has served as a director of Harken Energy Corporation since 1997 and
a consultant to Smith International, Inc. since 1991. From 1987 to 1991, Mr.
Smith was Vice President of Customer Relations for Smith International, Inc.
From 1965 to 1987, he held numerous positions, including many executive
offices with Smith Tool, Inc., a subsidiary of Smith International, Inc. Mr.
Smith has more than 30 years of experience in the oil services industry. Mr.
Smith received a BA from Claremont McKenna College.

         JEFFREY B. POLLICOFF has been a director of the Company since
November 10, 1999. Mr. Pollicoff has been the Managing Partner with
Pollicoff, Smith & Remels, L.L.P. since 1991, and has been with the firm
since 1982. From 1981 to 1982, Mr. Pollicoff served as Executive Vice
President of Norris Petroleum Company and Care Drilling Company. From 1979 to
1981, Mr. Pollicoff served as Vice President and Energy Loan Officer for
Texas Commerce Bank. From 1974 to 1979, he held several engineering positions
at Atlantic Richfield Corporation. Mr. Pollicoff is a member of the American
Bar Association, State Bar of Texas, Houston Bar Association and College of
the State Bar of Texas. He received a BS decree in Electrical Engineering
from Texas A&M University in 1974 and a J.D. from the University of Houston
Law School in 1980.

         DAVID B. CHRISTOFFERSON joined the Company in 1989 and served as a
director until May 14, 1998. Mr. Christofferson currently is Senior Vice
President, Secretary and General Counsel of the Company. He also serves as
its Principal Financial Officer. Mr. Christofferson has been active in the
natural gas and oil industry for over 20 years. He also served as General
Counsel to two independent natural gas and oil companies and to a natural gas
marketing company. Mr. Christofferson is a member of the Texas Independent
Producers and Royalty Owners Association. He received a BBA in finance and a
Juris Doctor from the University of Oklahoma. He also received a Masters of
Divinity degree from Phillips University. He is admitted to practice law in
Oklahoma.

KEY OFFICERS

         In addition to the directors and executive officers listed above,
the following employees have significant responsibilities with the Company.

         DALE W. ALEXANDER, 45, is Vice President-Exploitation. He served EPC
as a consultant in the area of reservoir and exploitation engineering from
1991 until May 14, 1998, when he became the Company's Vice President
--Exploitation. Mr. Alexander is responsible for determining pre-drill
economics, risk weighting drilling projects and coordination of reserve
reports. From 1988 to 1991, he was with Kamlock Oil & Gas Company. He was an
exploitation/reservoir engineer for EPC from 1983 to 1988. He also has worked
for Champlin Petroleum Company, and Union Oil of California. Mr. Alexander
has a BS in Petroleum Engineering from the University of Texas.

         JAMES SMITH, 58, is Vice President-Land. Mr. Smith joined the
Company in July of 2000, when he became the Company's Vice President of Land.
From 1998 to 1999, he served as management consultant to various joint
venture groups, including OMNITRANS, Lone Star Broadcasting and Selected
Lands Corporation. From 1988 to 1998, he served as a business and financial
consultant to a variety of companies. From 1980 to 1988 he was with Universal
Resources Corporation where he worked in land management and as an assistant
exploration manager. From 1971 to 1980, he worked in various staff and
management positions in the land departments at Statex Petroleum, Tenneco
Exploration and Ashland Exploration. Mr. Smith has a BA in Political Science
and Speech from Lamar University and attended South Texas College of Law and
the University of Oklahoma.

         ERIC GARDNER, 37, is Exploration Manager in the Houston office. Mr.
Gardner joined the Company in

                                       48
<PAGE>

September of 1999. From 1994 to 1999 he served as project leader and senior
explorationist at 3DX Technologies Inc. From 1985 to 1994 he was a senior
geophysicist at Amoco Production Company. He received a BS in Engineering
Physics from Colorado School of Mines in 1985.

         WILLIAM L. JACKSON, 45, is Senior Vice President-Operations. Mr.
Jackson joined EPC in 1982 and, on May 14, 1998, became the Company's Chief
Engineering Officer responsible for all oil and gas drilling, completion,
workover, and production operations. He previously served with Acock
Engineering and Mueller Engineering as an on-site petroleum engineering
consultant on drilling and workovers for oil and gas wells in the South Texas
area. He received a BS in Petroleum Engineering and an MBA from the
University of Texas.

         MICHAEL E. MOORE, 43, is Vice President-Exploration. Mr. Moore
joined EPC in 1982 as a staff geologist and became the Company's Vice
President-Exploration on May 14, 1998. Mr. Moore is responsible for reviewing
all outside geological projects as well as supervising the activities of
in-house and retainer geological staff. He previously was employed as a field
geologist with J.R. Weber, Inc., a consulting firm in Denver, Colorado. He
received a BS in Geology from the University of Texas.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

         Section 16(a) of the Exchange Act requires the Company's directors,
executive officers and persons who own more than 10% of a registered class of
the Company's equity securities, to file reports of ownership on Form 3 and
changes in ownership on Form 4 or 5 with the Commission. Such officers,
directors and 10% shareholders also are required by Commission rules to
furnish the Company with copies of all Section 16(a) reports they file. Based
solely on its review of the copies of such forms received by it, or written
representations from certain reporting persons that they were not required to
file a Form 5, the Company believes that, during the fiscal year ended
December 31, 2000, its officers, directors and 10% shareholders complied with
all Section 16(a) filing requirements applicable to such individuals.

ITEM 10. EXECUTIVE COMPENSATION

         The following table sets forth the total remuneration paid during
2000, 1999, and 1998 to the individuals who served as Chief Executive Officer
of the Company during 2000 and the Company's other most highly compensated
officers who received compensation in excess of $100,000 during 2000.

                                       49
<PAGE>

                             SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                                     LONG-TERM COMPENSATION
                                                                              -----------------------------------
                                             ANNUAL COMPENSATION(1)                    AWARDS             PAYOUTS
                                     -------------------------------------    -----------------------     -------
                NAME                                               OTHER                   SECURITIES                     ALL
                 AND                                               ANNUAL     RESTRICTED   UNDERLYING                    OTHER
              PRINCIPAL                                           COMPENS-       STOCK      OPTIONS/       LTIP          COMPEN-
              POSITION              YEAR  SALARY($)  BONUS($)(5)  ATION($)     AWARD(S)    SARS(#)(2)     PAYOUTS       SATION($)
              --------              ----  ---------  -----------  --------     --------    ----------     -------       ---------
<S>                                 <C>   <C>        <C>          <C>         <C>          <C>            <C>           <C>
Michael E. Johnson(3).......        2000  $200,000      $84,771    ------       ------      600,000        ------         ------
   President and                    1999  $200,000      ------     ------       ------      ------         ------         ------
   Chief Executive Officer          1998  $125,000      ------     ------       ------      ------         ------         ------
David W. Berry(4)...........        2000  $155,000      $65,698    ------       ------      600,000        ------         ------
   Chairman of the Board            1999  $155,000      ------     ------       ------      ------         ------         ------
                                    1998  $147,079      ------     ------       ------      ------         ------       $264,000(6)
David B Christofferson......        2000  $130,000      $55,101    ------       ------      150,000        ------         ------
   Senior Vice President and        1999  $130,000      ------     ------       ------      ------         ------         ------
   Principal Financial Officer      1998  $121,606      ------     ------       ------      ------         ------       $224,000(6)
William L. Jackson..........        2000  $114,700      $47,401    ------       ------      75,000         ------         ------
   Senior Vice President -          1999  $114,700      ------     ------       ------      ------         ------         ------
   Operations                       1998  $ 71,688      ------     ------       ------      ------         ------         ------
Dale Alexander..............        2000  $100,641      $40,266    ------       ------      100,000        ------         ------
   Vice President -                 1999  $ 95,000      ------     ------       ------      ------         ------         ------
   Exploitation                     1998  $ 59,375      ------     ------       ------      ------         ------         ------
</TABLE>
------------------------------
(1)      Does not include perquisites and other personal benefits that are the
         lesser of either $50,000 or 10% of the total of annual salary and
         bonus.
(2)      Represents the number of shares of common stock issuable pursuant to
         vested and non-vested stock options which were granted during the year.
(3)      Mr. Johnson became the Chief Executive Officer of the Company on May
         14, 1998.
(4)      Mr. Berry served as Chief Executive Officer through May 14, 1998.
(5)      The Company has instituted a bonus plan which is significantly based
         upon dollars expended during a given year on drilling and completion
         costs contrasted with the present value return in the form of net
         revenue received and projected to be received as determined by
         engineering evaluation of such drilled projects. 1999 operations
         results were primarily used to determine the 2000 bonus. 2000
         operations results will primarily determine the 2001 bonus. The bonus
         may be paid up to 50% in common stock, based upon market value at the
         time of issuance, at the election of the Company.
(6)      Upon the closing of the Acquisitions, previously existing incentive
         agreements and contract settlement agreements with both Mr. Berry and
         Mr. Christofferson required total payments of $264,000 to Mr. Berry and
         $224,000 to Mr. Christofferson. These amounts were paid 50% in cash and
         50% pursuant to promissory notes due in January of 1999 to each
         individual. See "Certain Transactions".

OPTION GRANTS

         The option grants made in 2000 to the individuals named in the Summary
Compensation Table above are as set forth in the following table:

<TABLE>
<CAPTION>
                                                                     Individual Grants
                                       -------------------------------------------------------------------------------
                                                                     % OF TOTAL
                                       NUMBER OF SECURITES        OPTIONS GRANTED TO     EXERCISE
                                          OF UNDERLYING          EMPLOYEES IN FISCAL     PRICE PER        EXPIRATION
NAME                                     OPTIONS GRANTED             YEAR 2000(1)          SHARE             DATE
----                                   ---------------------    ---------------------    -----------     -------------
<S>                                    <C>                      <C>                      <C>             <C>
Michael E. Johnson............              600,000(2)                     25.3%             $2.375        5/14/08
David W. Berry................              600,000(2)                     25.3%             $2.375        5/14/08
David B Christofferson........              150,000(2)                      6.3%             $2.375        5/14/08
William L. Jackson............               75,000(2)                      3.2%             $2.375        5/14/08
Dale W. Alexander.........                  100,000(2)                      4.2%             $2.375        5/14/08
</TABLE>

                                       50
<PAGE>

-------------------
(1) Based on options to purchase a total of 2,376,999 shares of Common Stock
     granted during 2000, of which 244,331 (or 10.3%) have expired.
(2) Consists of options issued under the Esenjay Exploration, Inc. Long Term
     Incentive Plan, 66.67% of which are currently exercisable.

OPTION REPRICING

         There were no option repricings made in 2000 to the individuals
named in the Summary Compensation Table above.

OPTION EXERCISE AND YEAR-END VALUES

         The following table sets forth certain information as of December
31, 2000 with respect to the unexercised options to purchase Common Stock to
the individuals named in the Summary Compensation Table above. None of such
individuals exercised any stock options during 2000.

<TABLE>
<CAPTION>
                                DECEMBER 31, 2000 OPTION/SAR VALUES

                                                                              NUMBER OF                VALUE OF
                                                                              SECURITIES              UNEXERCISED
                                                                              UNDERLYING              IN-THE-MONEY
                                                                              UNEXERCISED            OPTIONS/SARS AT
                                                                            OPTIONS/SARS AT         DECEMBER 31, 2000
                                                                           DECEMBER 31, 2000
                                        SHARES
                                       ACQUIRED            VALUE              EXERCISABLE/            EXERCISABLE/
NAME                                ON EXERCISE(#)        REALIZED($)        UNEXERCISABLE           UNEXERCISABLE(1)
-------------------------------     ---------------    -----------------    ----------------        ------------------
<S>                                 <C>                <C>                  <C>                     <C>
Michael E. Johnson(2)......             ------              ------           400,000/200,000         $925,200/$462,600
David W. Berry(3)..........             ------              ------           432,000/200,000         $954,256/$462,600
David B Christofferson(4)..             ------              ------            158,667/50,000         $284,569/$115,650
William L. Jackson(2)......             ------              ------             50,000/25,000         $115,650/$57,825
Dale W. Jackson(2).........             ------              ------             66,667/33,333         $154,200/$77,099
</TABLE>

--------------
(1)      Based on the last sale price of the Common Stock on the Nasdaq
         Small-Cap Market on December 29, 2000 of $4.688.
(2)      All options are exercisable at a price of $2.375 per share.
(3)      400,000 currently exercisable options are exercisable at a price of
         $2.375 per share and 32,000 currently exercisable options are
         exercisable at a price of $3.78 per share. All options not currently
         exercisable are exercisable at a price of $2.375 per share.
(4)      100,000 currently exercisable options are exercisable at a price of
         $2.375 per share and 58,667 currently exercisable options are
         exercisable at a price of $3.78 per share. All options not currently
         exercisable are exercisable at a price of $2.375 per share.

DIRECTORS' COMPENSATION

         The Board of Directors has adopted a standard compensation policy
for each of its directors whereby each director is paid a quarterly fee of
$5,625. There are currently no additional amounts paid for committee
participation or special assignments.

         The Board of Directors has also instituted a standardized
compensation arrangement for each director who began service on the board of
directors on May 15, 1998. This includes all directors other than Mr.
Pollicoff. In this regard, in April of 2000 each such director was issued:

         o        an option to purchase 12,000 shares of common stock at an
                  exercise price of $1.83 per share exercisable through May 15,
                  2008; and

                                       51
<PAGE>

         o        an option to purchase an additional 12,000 shares of common
                  stock at a price of $2.10 per share exercisable through May
                  15, 2009; and

         o        provided that the director still serves on the board of
                  directors on May 15, 2001, an option to purchase an additional
                  12,000 shares of common stock at a price of $2.38 per share
                  exercisable through May 15, 2010.

         In conjunction therewith, each such director has purchased, and in
April of 2000 was issued, 12,000 shares of common stock at a price of $1.83 per
share payable one-third upon subscription, one-third on or before May 15, 2000,
and one-third on or before May 15, 2001.

         Mr. Berry is not an officer of the Company but serves it full time in
his role as Chairman of the Board of Directors. Accordingly, he receives a
salary and other benefits for his services. (See Item 10-Executive
Compensation).

         Mr. Pollicoff has been granted a similar compensation package. In this
regard, he has been issued in May 2000:

         o        an option to purchase 12,000 shares of common stock at an
                  exercise price of $1.83 per share, exercisable through May 15,
                  2008; and

         o        provided that he still serves on the board of directors on May
                  15, 2001, an option to purchase 12,000 shares of common stock
                  at an exercise price of $2.10 per share, exercisable through
                  May 15, 2009; and

         o        provided that he still serves on the board of directors on May
                  15, 2002, an option to purchase 12,000 shares of common stock
                  at an exercise price of $2.38 per share through May 15, 2010.

         In conjunction therewith, Mr. Pollicoff also purchased 12,000 shares of
common stock at a price of $1.83 per share payable one-third upon subscription,
one-third one year thereafter, and the balance two years after purchase.


ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

EMPLOYMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS

         There were no employment contracts in effect with any named executive
officer in 2000.

         The Company has adopted an Employee Incentive and Severance
Protection Plan that covers all employees including its officers. Pursuant to
such plan, in the event the Company was acquired by a third party or incurred
a change in control, and the individual employee agreed to remain with the
Company for a minimum of six months after such change in control, then at the
end of such six months the employee would be paid a one time bonus equal to
six months of their base salary.

BENEFICIAL OWNERSHIP OF COMMON STOCK

         The following table sets forth certain information, as of March 29,
2001, with respect to the Common Stock owned by (i) each person known by
management to own beneficially more than 5% of the Company's outstanding
Common Stock; (ii) each of the Company's Directors and each executive
officers who received compensation in 2000 in excess of $100,000; and (iii)
all Directors and executive officers of the Company as a group. Unless
otherwise noted, the persons named below have sole voting and investment
power with respect to such shares.

                                       52
<PAGE>

<TABLE>
<CAPTION>
                                                                   NUMBER OF                           PERCENT OF
NAME OF BENEFICIAL OWNER                                          SHARES(1)                            CLASS(2)(3)
------------------------                                  ----------------------------              ------------------
<S>                                                       <C>                                       <C>
Esenjay Petroleum Corporation(4).................                  4,896,415                               25.8%
Aspect Resources LLC(5)..........................                  4,748,156                               25.0%
David W. Berry(6)................................                    867,751(7)                            4.6%
Alex M. Cranberg(5)..............................                  4,850,268(8)                            25.6%
Michael E. Johnson(4)............................                  5,650,303(9)(10)                        29.8%
Charles J. Smith(4)..............................                  4,985,415(9)                            26.3%
Alex B. Campbell(5)..............................                     48,713(11)                            *
William D. Dodge, III(6).........................                     48,000(11)                            *
Jack P. Randall(6)...............................                     48,000(11)                            *
Hobart A. Smith(6)...............................                     48,000(11)                            *
Jeffrey B. Pollicoff(6)..........................                     50,000(11)                            *
William L. Jackson(4)............................                     99,008(12)                            *
Dale W. Alexander(4).............................                    111,886(13)                            *
David B Christofferson(6)........................                    218,231(14)                            1.1%
Wellington Management Company, LLP(15)...........                  1,135,000                                6.0%
Centennial Energy Partners, L.L.C.(16)...........                    965,000                                5.1%
     All executive officers and Directors as a group (11 persons)  2,241,477(17)                           11.8%
</TABLE>
--------------------------
* Less than 1%

(1)      Includes all shares of common stock with respect to which each person,
         executive officer or director who directly, through any contract,
         arrangement, understanding, relationship or otherwise, has or shares
         the power to vote or to direct voting of such shares or to dispose or
         to direct the disposition of such shares. Includes shares that may be
         purchased under stock options exercisable within 60 days.
(2)      Based on 18,980,698 shares of common stock outstanding at March 29,
         2001, plus, for each beneficial owner, those number of shares
         underlying exercisable options held by each executive officer or
         director.
(3)      Percent of class for any stockholder listed is calculated without
         regard to shares of common stock issuable to others upon exercise of
         outstanding stock options or warrants. Any shares a stockholder is
         deemed to own by having the right to acquire by exercise of a stock
         option or warrant are considered to be outstanding solely for the
         purpose of calculating that stockholder's ownership percentage.
(4)      Address: c/o Esenjay Exploration, Inc., 500 North Water Street, Suite
         1100 South, Corpus Christi, Texas 78471.
(5)      Address:  511 16th Street, Suite 300, Denver, Colorado 80202.
(6)      Address: c/o Esenjay Exploration, Inc., 500 Dallas, Suite 2920,
         Houston, Texas 77002
(7)      Includes 668,000 shares of common stock issuable upon the exercise of
         stock options currently exercisable or exercisable within sixty days.
(8)      Includes (i) 54,112 shares of common stock owned by the spouse of Mr.
         Cranberg, and (ii) 4,748,156 shares of common stock owned by Aspect, as
         to which Mr. Cranberg disclaims beneficial ownership. Also includes
         36,000 shares of common stock issuable upon the exercise of options
         currently exercisable or exercisable within 60 days.
(9)      Includes 4,896,415 shares of common stock owned by EPC, as to which
         Messrs. Johnson and Smith disclaim beneficial ownership.
(10)     Includes 636,000 shares of common stock issuable upon the exercise of
         options currently exercisable or exercisable within 60 days.
(11)     Includes 36,000 shares of common stock issuable upon the exercise of
         options currently exercisable or exercisable within 60 days.
(12)     Includes 75,000 shares of common stock issuable upon the exercise of
         stock options currently exercisable or exercisable within sixty days
         and 1,753 shares of common stock owned by the spouse of Mr. Jackson.
(13)     Includes 100,000 shares of common stock issuable upon the exercise of
         stock options currently exercisable or exercisable within sixty days.
(14)     Includes 208,667 shares of common stock issuable upon the exercise of
         stock options currently exercisable or exercisable within sixty days.
(15)     Address: 75 State Street, Boston, Massachusetts 02109.

                                       53
<PAGE>

(16)     Address: 900 Third Ave., Suite 1801, New York, New York 10022. Based
         solely upon statements of beneficial ownership filed of record,
         Centennial Energy Partners, L.L.C. beneficially owns 938,800 shares of
         common stock, which shares comprise 4.9% of the total outstanding
         shares. Joseph H. Reich and Peter K. Seldin of the same address are
         also beneficial owners of said 938,800 shares of common stock based
         solely upon statements of beneficial ownership filed of record. Based
         upon other information available to the Company, Centennial Energy
         Partners, L.L.C. currently is the beneficial owner of 965,000 shares of
         common stock of the Company, which shares comprise 5.1% of the total
         outstanding shares.
(17)     Includes 1,903,667 shares issuable pursuant to stock options held by
         executive officers and directors that are currently exercisable. Does
         not include any shares of common stock as to which beneficial ownership
         is disclaimed.


ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         The Company and Aspect Management Corporation, the manager of Aspect
("Aspect Management"), entered into a Geotechnical Services Consulting
Agreement on May 14, 1998, pursuant to which Aspect Management may perform
geotechnical services for the Company. To the extent that Aspect Management
pays or advances costs or expenses associated with certain assets on behalf
of the Company, and to the extent Aspect Management hires independent
contractors, such costs and expenses will be billed to the Company. Under the
Geotechnical Services Consulting Agreement, Aspect Management must obtain the
Company's approval to enter into any related contract or agreement that has a
cost exceeding $50,000 net to the Company. The Company must pay Aspect
Management for services rendered in an amount equal to Aspect's employee
costs, overhead costs and general and administrative costs associated with
the services rendered thereunder. The agreements terminate on May 14, 2002,
unless terminated by either party with 90 days' written notice to the other
party. No such services were provided in 1999 or 2000 under this agreement.

         The Company and Aspect Management also entered into a Land Service
Consulting Agreement on May 14, 1998, pursuant to which Aspect Management
could provide certain land related services to the Company in connection with
certain oil and gas properties to which both parties share an ownership
interest. This agreement contained terms and provisions similar to the
above-referenced Geotechnical Services Consulting Agreement. No services were
provided pursuant to this Land Service Consulting Agreement in 1999 and the
parties agreed to terminate the agreement. It was terminated in 1999 and is
no longer in effect.

         In the second quarter of 1999, the Company closed an agreement
pursuant to which it sold to Aspect a 12.5% (of 100%) interest in the Caney
Creek Project, a 12% (of 100%) interest in the Gillock Project, and all of
the Company's undeveloped property interests in the West Beaumont project
area for $2,610,000. Proceeds from the sale were used to help settle amounts
due Aspect. In that Aspect is a related party, closing was subject to receipt
of an independent fairness opinion which was obtained.

         The Company operates certain wells in which Aspect and EPC own
interests. Pursuant to joint operating agreements which include the same
terms as apply to unrelated third parties, Aspect and EPC pay normal
operation costs associated with such wells. Conversely, Aspect operates
certain Exploration Projects and wells in which the Company owns interests.
Pursuant to joint operating agreements which include the same terms as apply
to unrelated third parties, the Company pays normal operation costs
associated with such Exploration Projects and wells.

         In 2000 Sommersault, LLC, an investment entity owned 100% by David
W. Berry, the Chairman of the Board of Directors of the Company, purchased
working interests in three exploratory drilling prospects operated by the
Company. All of the working interests were purchased pursuant to the same
terms as concurrent transactions with industry partners. The total costs paid
by Mr. Berry to the Company in 2000 were less than $100,000.

         In 1999 the Company retained the firm of Randall and Dewey, Inc.
("Randall and Dewey") to assist in the marketing and sale of interests in its
Raymondville Project in Willacy County, Texas. Jack P. Randall, a director of
the Company, is also President and CEO and a substantial shareholder of
Randall and Dewey. Pursuant to the agreement with Randall and Dewey, the
Company reimbursed Randall and Dewey for $30,715 in costs incurred in 1999.
In addition, upon closing of a sale of interests in the Raymondville Project
in March of 2000, the Company paid Randall and Dewey a transaction fee of
$382,192. This fee included a base transaction fee of $250,000 plus 0.75% of
the total

                                       54
<PAGE>

selling price. The Company's share of the fee was approximately 80.88% with
third parties who also sold interests in the Raymondville Project, including
EPC, reimbursing the Company for their 19.12% pro rata share of the total
fee. The Company believes the fee charged was the normal fee which would be
charged to third parties for comparable services.

         In 2000 the Company retained the firm of Randall and Dewey to
initiate, analyze and manage potential transactions which may better maximize
shareholder value. Deutsche Bank Securities, Inc. was retained to advise the
Company concerning various strategic alternatives in this regard. Potential
alternatives included possible mergers, acquisitions or a potential cash
sale. The company does not presently intend to aggressively pursue such
options. In 2000 the Company paid Randall and Dewey an advisory fee of
$150,000. In the event a transaction was consummated pursuant to its
agreement with Randall and Dewey, it would owe Randall and Dewey a
transaction fee of 0.75 percent of the value of the transaction plus 1.125%
of the value of the transaction in excess of $56.7 MM.

         On December 31, 2000 and 1999, the Company had accounts receivable
from employees and affiliates totaling net amounts of $124,267 and $553,950,
respectively. The December 31, 2000 balance includes net accounts payable due
to Aspect in the amount of $122,506. The December 31, 2000 and 1999 balances
include net accounts receivable due from EPC in the amount of $101,199 and
$190,923, respectively. At December 31, 1999, the Company had a net account
payable due to Aspect in the amount of $2,083,913.

         Any future transaction between the Company and any of its Directors,
officers or owners of five percent or more of the Company's then outstanding
Common Stock will be on terms no less favorable than would reasonably be
expected from an independent third party, and will be approved by a majority
of the Directors who do not have an interest in the proposed transaction and
who have had access to the Company's outside legal counsel with respect to
such transaction.









                                       55
<PAGE>

                                     PART IV

ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K

<TABLE>
<CAPTION>
EXHIBIT                    NAME OF EXHIBIT
-------                    ---------------
<S>      <C>
2(a)     Plan and Agreement of Merger of Esenjay Exploration, Inc. and 3DX
         Technologies Inc. is incorporated by reference to the Company's
         Quarterly Report on Form 10QSB for the quarter ended March 31, 1999
         dated May 19, 1999 wherein the same appears as Exhibit 2.

3(a)     Certificate of Incorporation of the Company as incorporated by
         reference to the Company's Registration Statement number 333-53581
         dated May 21, 1998 wherein the same appeared as Exhibit 3(a).

3(b)     By-Laws of the Company as incorporated by reference to the Company's
         Registration Statement number 333-53581 dated May 21, 1998 wherein the
         same appeared as Exhibit 3(c).

4(a)     See Articles V, VI and X of the Company's Certificate of Incorporation
         and Articles I, II, V and VI of the Company's By-Laws as provided at
         Exhibits 3(a) and 3(b) above.

4(b)     Certificate of Designations of Esenjay Exploration, Inc. establishing
         the designations, preferences, limitations, and relative rights of its
         Series A Convertible Preferred Stock is incorporated by reference to
         the Company's Quarterly Report on Form 10-QSB for the quarter ended
         September 30, 1999 dated November 15, 1999 wherein the same appears as
         Exhibit 4.

10(a)    $20,000,000 Amended and Restated Credit Agreement dated as of October
         13, 1998, between Esenjay Exploration, Inc. as the borrower and Bank of
         America NT&SA as the lender, as incorporated by reference to the
         Company's Annual Report on Form 10-KSB for the fiscal year ended
         December 31, 1998 dated April 14, 1999, wherein the same appears as
         Exhibit 10(c).

10(b)    Credit Agreement by and between Esenjay Exploration, Inc. and Duke
         Energy Financial Services, Inc. dated as of January 28, 1999, as
         incorporated by reference to the Company's Annual Report on Form 10-KSB
         for the fiscal year ended December 31, 1998 dated April 14, 1999,
         wherein the same appears as Exhibit 10(d).

10(c)    Loan Agreement by and between Frontier Natural Gas Corporation and 420
         Energy Investments, Inc. dated March 1, 1996, as currently in effect as
         incorporated by reference to the Company's Annual Report on Form 10-KSB
         for the fiscal year ended December 31, 1995 dated March 29, 1996,
         wherein the same appears as Exhibit 10(r).

10(d)    Employee Option Plan-1997 as currently in effect as incorporated by
         reference to the Company's Annual Report on Form 10-KSB for the fiscal
         year ended December 31, 1997 dated April 6, 1998, wherein the same
         appears as Exhibit 10(o).

10(e)    Warrant Agreement between Frontier Natural Gas Corporation and Gaines,
         Berland Energy Fund, L.P. dated January 14, 1998, as incorporated by
         reference to the Company's Registration Statement number 333-53581
         dated May 21, 1998 wherein the same appeared as Exhibit 10(q).

10(f)    Warrant Agreement between Frontier Natural Gas Corporation and Esenjay
         Petroleum Corporation dated January 14, 1998, as incorporated by
         reference to the Company's Registration Statement number 333-53581
         dated May 21, 1998 wherein the same appeared as Exhibit 10(r).

10(g)    Warrant Agreement between Frontier Natural Gas Corporation and Aspect
         Resources LLC dated January 14, 1998, as incorporated by reference to
         the Company's Registration Statement number 333-53581 dated May 21,
         1998 wherein the same appeared as Exhibit 10(s).

10(h)    Warrant Agreement between Frontier Natural Gas Corporation and Gaines,
         Berland Energy Fund, L.P. dated

                                       56
<PAGE>

         January 23, 1998, as incorporated by reference to the Company's
         Registration Statement number 333-53581 dated May 21, 1998 wherein the
         same appeared as Exhibit 10(t).

10(i)    Warrant Agreement between Frontier Natural Gas Corporation and Esenjay
         Petroleum Corporation dated January 23, 1998, as incorporated by
         reference to the Company's Registration Statement number 333-53581
         dated May 21, 1998 wherein the same appeared as Exhibit 10(u).

10(j)    Warrant Agreement between Frontier Natural Gas Corporation and Aspect
         Resources LLC dated January 23, 1998, as incorporated by reference to
         the Company's Registration Statement number 333-53581 dated May 21,
         1998 wherein the same appeared as Exhibit 10(v).

10(k)    Credit Agreement by and between Esenjay Exploration, Inc. and Deutsche
         Bank AG, New York and/or Cayman Islands Branches, dated as of January
         25, 2000, as incorporated by reference to the Company's Annual Report
         on Form 10-KSB for the fiscal year ended December 31, 1999, dated April
         13, 2000, wherein the same appears as Exhibit 10(m).

10(l)*   Amendment Number One to Credit Agreement by and between Esenjay
         Exploration, Inc. and Deutsche Bank AG, New York and/or Cayman Islands
         Branch, dated as of January 24, 2001.

10(m)*   Amendment Number Two to Credit Agreement by and between Esenjay
         Exploration, Inc. and Deutsche Bank AG, New York and/or Cayman Islands
         Branch, dated as of February 23, 2001.

10(n)    Esenjay Exploration, Inc. Long Term Incentive Plan is incorporated by
         reference to the Company's Definitive Proxy Statement filed September
         7, 2000 wherein it appeared as an exhibit.

11*      Statement of Earnings per Share
21*      Subsidiaries of Registrant.
(b)      Reports on Form 8-K. Form 8-K filed on October 2, 2000 is incorporated
         by reference.
</TABLE>

--------------------
*Filed herewith

                                       57
<PAGE>

                                   SIGNATURES

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

                                    ESENJAY EXPLORATION, INC.


Date: April 16, 2001                By: /s/ MICHAEL E. JOHNSON
                                        ----------------------------------------
                                        Michael E. Johnson, President,
                                        Chief Executive Officer and Director

         Pursuant to the requirements of Section 13, or 15(d) of the Securities
and Exchange Act of 1934, the registrant has duly caused this report to be
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.

<TABLE>
<S>                                <C>
Date: April 16, 2001               /s/ David B. Christofferson
                                   ---------------------------------------------
                                   David B Christofferson, Senior Vice President
                                   General Counsel and Chief Financial Officer


Date: April 16, 2001               /s/ David W. Berry
                                   ---------------------------------------------
                                   David W. Berry, Chairman and Director


Date:  April 16, 2001              /s/ Alex B. Campbell
                                   ---------------------------------------------
                                   Alex B. Campbell, Director


Date:  April 16, 2001              /s/ Jeffrey B. Pollicoff
                                   ---------------------------------------------
                                   Jeffrey B. Pollicoff, Director


Date:  April 16, 2001              /s/ Jack P. Randall
                                   ---------------------------------------------
                                   Jack P. Randall, Director


Date:  April 16, 2001              /s/ Hobart A. Smith
                                   ---------------------------------------------
                                   Hobart A. Smith, Director
</TABLE>

                                       58