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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, 2001

/ /              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:

                                                           NAME OF EACH EXCHANGE
        TITLE OF EACH CLASS                                 ON WHICH REGISTERED
        -------------------                                ---------------------
              None                                                 None

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

                                  COMMON STOCK

     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: $41,661,926.

     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 $25,454,000 on March 28, 2002 (based on the last sales price of
$2.81 per share as reported on the NASDAQ Stock Market).

     19,140,667 shares of the registrant's common stock were outstanding as of
March 28, 2002.

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                            ESENJAY EXPLORATION, INC.
                        FOR YEAR ENDED DECEMBER 31, 2001

                                TABLE OF CONTENTS
                                   FORM 10-KSB

                                     PART I

<Table>
<Caption>
ITEM                                                                             PAGE
----                                                                             ----
<S>                                                                               <C>
1.    Description of Business...................................................   3

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

3.    Legal Proceedings.........................................................  20

4.    Submission of Matters to a Vote of Security Holders.......................  20

                                     PART II

5.    Market for Common Equity and Related Stockholder Matters..................  21

6.    Management's Discussion and Analysis......................................  21

7.    Financial Statements......................................................  33

8.    Changes in and Disagreements with Accountants on
       Accounting and Financial Disclosure......................................  52

                                    PART III

9.    Directors, Executive Officers, Promoters and Control Persons;
       Compliance with Section 16(a) of the Exchange Act........................  52

10.   Executive Compensation....................................................  52

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

12.   Certain Relationships and Related Transactions............................  52

                                     PART IV

13.   Exhibits and Reports on Form 8-K..........................................  53

      Signatures................................................................  54
</Table>

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                                     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. Esenjay Exploration Inc.'s (the "Company) 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

     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 greatly expanded its exploration activities when it acquired interest in
28 exploration projects located along the Texas Gulf Coast. The Exploration
Projects also include the Company's interests in these projects and projects
originated since that time. 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. 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. 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 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. On March 17, 2002, the
Company and Santos Americas and Europe Corporation and ECM Acquisition Company,
(collectively "Santos") entered into an agreement providing for Santos'
acquisition of all issued and outstanding common stock of the Company by means
of a tender offer at a price of US$2.84 per share in cash and a follow-on merger
at the same price. Under the terms agreed, Santos initiated a formal offer on
March 26, 2002. The offer must remain open through at least April 22, 2002. It
is conditioned upon the receipt of at least a majority of the Company's
outstanding shares. If Santos receives at least a majority of such shares, it
will, subject to various typical contingencies such as the absence of any
material adverse changes, close on the purchase of shares tendered and then
proceed to acquire all remaining outstanding shares through a subsequent merger,
the timing of which would be announced at a later date. Shareholders who do not
participate in the tender offer would also receive $2.84 per share in cash in
the merger. At a meeting held on Saturday, March 16, 2002, the Company's Board
of Directors voted to accept and support the Santos tender offer and voted to
recommend that the Company's shareholders accept the cash tender offer and
approve the merger. In addition, as a condition to the offer, two major
shareholders and the Chairman of the Board of Directors agreed to tender all of
the shares owned by them (representing 9,991,662 shares or 52% of the Company's
total outstanding shares) in the Santos tender offer and have granted Santos the
option to acquire all of their shares if the tender offer is not consummated for
certain reasons. In voting to accept and support the Santos tender offer, The
Company's Board of Directors considered a number of factors. The Company has
historically been forced to constrain capital spending and to sell larger than
desired interests in its exploration projects and prospects in order to fund its
capital program, which has resulted in lower than expected reserve growth. As
part of the Company's evaluation of strategic alternatives, a process, initially
undertaken in late 2000, the Board of

                                        3
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Directors recognized that its inability to access sufficient capital at an
acceptable cost would be an ongoing impediment to the Company's ability to fully
exploit its sizable asset base. The Company and it financial advisors do not
anticipate a meaningful improvement in the access to affordable capital in the
foreseeable future, and as a result it will be difficult to maximize the
substantial reserve potential that the Company believes exists in its prospect
inventory. With this in mind, and after revisiting strategic alternatives and
potential transactions available to the Company in the current marketplace, the
Board of Directors recommended that the Company's shareholders accept the Santos
offer. In the event the tender offer and merger are closed, the Company will not
continue as a public company but will be a wholly owned subsidiary of Santos.

     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 over 2,000 square miles, with additional
3-D seismic surveys planned. A significant number of the Exploration Projects
have reached the drilling stage, and the Company preliminarily budgeted
approximately $26 million to fund its drilling, completion, land and seismic
activities in 2002. This budget is currently being reviewed and it's anticipated
it will be reduced to a total amount ranging from $15 to $20 million in the
event the previously described tender offer is not closed. The budget is also
likely to be modified should the currently pending tender offer for the common
stock of the Company as described in the previous paragraph be closed.

     The Company, which utilizes the successful efforts method of accounting,
entered 2002 having grown from total 1998 gas and oil revenues of
approximately $1,372,000 and large operating cash flow deficits to a company
with $31,942,264 in oil and gas revenues and operating cash flow (net income
plus non-cash charges and exploration expenses, less gain on sale of assets)
of approximately $11.7 million in 2001.

     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 interests in the twenty-eight exploration projects
acquired in May, 1998 were underdeveloped, and were comprised primarily of
interests in unproven 3-D seismic based projects, which 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, 2001 the
unamortized balance was $1,641,900. In 2001 this amortization resulted in a
$3,457,000 expense. The amortization of properties acquired pursuant to the
May 1998 acquisitions will conclude in May of 2002.

     Impairments totaled $4,514,077 for the year ended December 31, 2001.
Impairments were primarily related to unproved property costs on projects
that management believes have diminished value based upon 2001 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 into the
second quarter of 2002, 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.

     As a result of the tax rules applicable to the acquisitions, the Company
may 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. 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. 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

                                        4
<Page>

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 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. The Company added 19.256 billion
cubic feet equivalent ("BCFE") of new gas and oil reserves from its 2000
drilling activities. 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.

                                        5
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     OVERVIEW OF 2001 ACTIVITIES. The Company entered 2001 expecting to continue
to expand its production and reserves via exploration activities on its
technology-enhanced projects. By utilizing capital available to it from
operating cash flow, financings and industry partner transactions, the Company
continued to pursue an aggressive exploration budget in its major trends of
activity.

     The Company participated in working interests in 46 wells which reached
total depth and were logged in 2001. Its net production increased slightly from
6,843,547 thousand cubic feet of natural gas equivalent using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate and natural gas liquids
("Mcfe") in 2000 to 7,350,939 in 2001. Its net proven reserves as of
December 31, 2001 totaled 18.3 billion cubic feet of natural gas equivalent
("Bcfe") down from 23.8 Bcfe at year-end 2000. The decrease was primarily
attributable to sales of project interests which totaled 8.3 net Bcfe. The
Company focused its exploratory drilling on higher risk, high potential return
prospects and delineation drilling on its Runnells and Hordes Creek Fields.
Success in the Runnells Field, as evidenced by the Runnells #5 and #7 wells
drilled in 2001, substantially increased proven reserves during the year;
however, the Company sold approximately 71% of its interest in the Runnells
Field in the fourth quarter of 2001 for net proceeds of $20.3 million plus
reimbursement of previously incurred cost on the Runnells #7 well attributable
to the interests sold. Accordingly, the net reserve increases attributable to
the delineation of the field were not reflected in year-end net reserve totals.
Delineation of the Hordes Creek Field has proceeded at a limited pace. The
Pierra Childrens Trust #3 well did not successfully expand the field. Further
delineation drilling is expected in the Hordes Creek field in 2002.

     The Company continues to believe it remains positioned to expand its net
proven reserves in 2002 via continued exploratory, delineation, and development
drilling. It believes that the rate of expansion will likely be proportionate to
the capital available to fund such activities. In the event the pending merger
as set forth in the Santos agreement does not close, the Company will continue
its business as historically conducted. It will also continue to look for
opportunities to consolidate business activities with an industry partner such
that more capital resources may be deployed to maximize the potential of it
Exploration Projects.

     In 2001 the Company also completed an amendment of its credit facility with
Deutsche Bank. As of year-end 2001, the amended facility provides for the bank
to loan up to $38,500,000 in two tranches. Tranche A is in the amount of
$30,000,000 with $13,500,000 established as the borrowing base and $7,689,071
outstanding at December 31, 2001. Tranche A will mature on August 13, 2002, at
which time it will convert to a four year quarterly amortizing term loan.
Tranche B is in the current amount of $8,500,000, of which the entire amount was
outstanding at December 31, 2001. It is payable, interest only, until due on
August 13, 2003, at which time the entire Tranche B balance is due.

     As of March 28, 2002, the Company has 19,140,667 total shares of common
stock outstanding. It employs 42 full time employees, including six in its
exploration and geophysical departments, six in its operations department, three
in its exploitation department, and nine 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

                                        6
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     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 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 May 1998 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

                                        7
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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 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. For example, 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:

                              EXPLORATION PROJECTS
<Table>
<Caption>
                                               ACRES LEASED OR UNDER OPTION AT         SQUARE MILES OF
                                                      MARCH 28, 2002(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
   Lafite/Allen Dome............           5,738.21       5,462.15        3,184.49             53              58.30%
   Gillock......................          13,753.81      11,712.70        4,351.27             70              37.15%
   Blessing.....................              80.00          80.00           27.15             22              33.94%
   Tidehaven....................           1,626.17       1,555.12          728.90             28              46.87%
   El Maton.....................           3,567.30       1,909.81        1,234.60             29              64.65%
   Midfield.....................             537.50         328.51          221.74             21              67.50%
   Markham......................           1,513.94       1,354.01          434.04              5              32.06%
   Buckeye Ranch................           2,987.07       2,813.35        1,361.99             40              48.41%
   Duncan Slough................           7,976.60       6,399.76        1,630.67             25              25.48%
   La Rosa......................              80.00          80.00            7.60             25               9.50%
   Vicksburg Area II Phase I....           3,329.46       3,317.02        1,244.30             76              37.51%
   Vicksburg Area II Phase II...           1,126.63       1,126.63          752.79             66              66.82%
   Wolf Point...................             632.00         632.00          174.75              8              27.65%
   Archie.......................             489.40         489.40           88.70             14              18.12%
   Raymondville.................          18,544.10      18,516.95        1,003.03             62               5.42%
   Smith Point..................                 --             --              --             80               7.50%
                                        ------------   -------------   ------------   ----------------
                  Frio Sub-Total          61,982.19      55,777.41       16,446.02            624
WILCOX CORE AREA
   Gila Bend....................             305.84         305.84           44.98             16              14.71%
   Hall Ranch...................           8,849.64       8,661.99        6,071.76             57              70.10%
   Hordes Creek.................           6,634.27       6,559.27        2,123.45             25              32.37%
   Mikeska W....................           4,190.87       3,691.99        1,635.13             32              44.29%
   Verdad.......................           3,054.12       2,928.00          732.02             40              25.00%
   Orangedale West..............             471.26         348.81          174.41             10              50.00%
</Table>

                                        8
<Page>

<Table>
<Caption>
                                               ACRES LEASED OR UNDER OPTION AT         SQUARE MILES OF
                                                      MARCH 28, 2002(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>
   Riverdale....................           6,114.55       6,114.55        1,156.65             40              18.92%
                                        ------------   -------------   ------------   ----------------
                Wilcox Sub-Total          29,620.55      28,610.45       11,938.40            220
TEXAS HACKBERRY CORE AREA
   Lox B........................           2,670.62       1,414.29          353.60             62              25.00%
   West Port Acres..............             691.05         422.32           52.77             21              12.50%
   Stowell/Big Hill.............           1,662.27         121.88           10.16             56               8.33%
   Cheek........................           8,890.02       5,672.11          679.17             48              11.97%
   Lovell Lake..................           6,085.06       4,061.79          548.43             65              13.50%
   West Beaumont................             328.15         328.15           25.18             23               7.67%
                                        ------------   -------------   ------------   ----------------
       Texas Hackberry Sub-Total          20,327.17      12,020.54        1,669.31            275
YEGUA CORE AREA
   Papalote.....................          23,900.76      23,523.19        9,577.51             98              40.72%
   Inez.........................             199.25         199.25           55.79             10              28.00%
   West Inez....................             112.92         112.91           98.80             10              87.50%
   Thomaston....................             122.04         122.04            6.10             54               5.00%
   South Louisiana Eocene.......           5,771.13       5,490.24        1,446.90             85              26.35%
   Howards Creek................           1,446.29       1,406.99          210.42             88              14.96%
                                        ------------   -------------   ------------   ----------------
                 Yegua Sub-Total          31,552.39      30,854.62       11,395.52            345
OTHER LOUISIANA
   Four Isle Dome...............              66.52          66.52            3.33             80               5.00%
   Starboard Lapeyrouse.........             447.15          29.88            3.12             35              10.44%
                                        ------------   -------------   ------------   ----------------
             Louisiana Sub-Total             513.67          96.40            6.45            115
OTHER TEXAS
   East Texas Pinnacle Reef(3)..             TBD            TBD             TBD               400               TBD
                                        ------------   -------------   ------------   ----------------
           Other Texas Sub-Total             TBD            TBD             TBD               400               TBD
MISSISSIPPI
   Thompson Creek...............             840.15         671.83          628.16             12              93.50%
   Melvin.......................             305.38         201.65           32.54             64              16.14%
                                        ------------   -------------   ------------   ----------------
           Mississippi Sub-Total           1,145.53         873.48          660.70             76
                                        ------------   -------------   ------------   ----------------

              TOTAL ALL PROJECTS         145,141.50     128,232.90       42,116.40          2,055
                                        ============   =============   ============   ================
</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

                                        9
<Page>

          license agreement, and to which the Company may acquire an interest
          pursuant to a geophysical technical services agreement with Aspect.

EXPLORATION PROJECT AREA DESCRIPTION.

     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. 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 16 active
3-D seismic survey areas that cover approximately 624 square miles. It plans to
drill and/or participate in approximately 17 wells in the Frio Trend in 2002.
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 plans to focus on the area where it has had
discoveries in 2001.

     WILCOX CORE AREA. In the Wilcox Trend, the Company has seven active 3-D
seismic survey areas covering approximately 220 square miles. It plans to drill
approximately 12 wells in the Wilcox Trend in 2002. 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 2002 and beyond so warrant.

     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 survey areas covering approximately 275 square miles. It does not
plan to drill in the Hackberry Trend in 2002.

     YEGUA CORE AREA. In the Yegua Trend, the Company currently has interests in
six active 3-D seismic survey areas. The Company will own interests in an
aggregate of approximately 345 square miles of 3-D seismic data in the trend in
2002. The Company expects to drill two wells in the Yegua Trend in 2002. 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 certain large oil companies have used 3-D seismic and CAEX
technologies for approximately 25 years, these methods were not affordable by
smaller, independent gas and oil companies until more recently, when improved
data acquisition equipment and techniques and computer technology became
available at reduced costs.

                                       10
<Page>

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. 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 typically 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
re-address 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 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. The
hedged volumes were as follows:

<Table>
<Caption>
      QUARTER ENDED     PRICE PER MMBtu   2001 (MMBtu/day)    2000 (MMBtu/day)
      -------------     ---------------   ----------------    ----------------
   <S>                       <C>                <C>                 <C>
   March 31st                $2.45              7,161               9,381
   June 30th                 $2.45              6,880               9,031
   September 30th            $2.45              6,600               8,646
   December 31st             $2.45              6,319               8,278
</Table>

     In January 2001 these hedges were replaced with 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. Volumes committed to the collar structure include
4,500

                                       11
<Page>

MMBtu per day for calendar year 2003. These hedges are accounted for as cash
flow hedges pursuant to SFAS No. 133. See discussion of SFAS No. 133 accounting
at footnote eight of the financial statements.

     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. They
remained in place throughout their initial term and expired on
December 31, 2001. In October 2001, the Company hedged an additional 6,500
MMBtu/day of natural gas production for calendar year 2002 at a price of $2.90
per MMBtu. These hedges remain in place in addition to the previously described
collar.

     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.

         As a result of the above-referenced transactions, the Company has total
hedge and/or "collar" contracts covering total volumes as set forth below:

     NATURAL GAS

<Table>
<Caption>
    QUARTER ENDED      2001 (MMBtu/day)   2002 (MMBtu/day)    2003 (MMBtu/day)
    -------------      ----------------   ----------------    ----------------
   <S>                      <C>                <C>                  <C>
   March 31st               12,383             15,000               4,500
   June 30th                12,900             14,500               4,500
   September 30th           13,000             14,000               4,500
   December 31st            13,000             13,500               4,500
</Table>

     OIL

<Table>
<Caption>
    QUARTER ENDED       2001 (Bbl/day)     2002 (Bbl/day)       2003 (Bbl/day)
    -------------       --------------     --------------       --------------
   <S>                       <C>                 <C>                  <C>
   March 31st                175                 0                    0
   June 30th                 168                 0                    0
   September 30th            161                 0                    0
   December 31st             154                 0                    0
</Table>

     First quarter 2002 hedges are estimated to approximate 95% of the Company's
natural gas production and none of its oil production for such quarter. Second
quarter hedges are estimated to approximate 85% of the Company's natural gas
production as additional developed wells come on line. 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 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. In 2001 purchasers accounting for more than
10% of the Company's total revenue were Dow Hydrocarbons & Resources/Duke Energy
Transportation & Trading/Tejas Gas Operating. The Company does not believe the
loss of any existing purchaser would have a material adverse effect on the
Company.

     The Company had a credit facility with Duke Energy Financial Services, Inc.
("Duke"), pursuant to which an ongoing agreement was established which 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.

                                       12
<Page>

     The Company expects that its daily production will 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 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' 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

                                       13
<Page>

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 which:

     -    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,

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

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

     -    requires pipelines to implement imbalance management services,

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

     -    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 rate making 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.

                                       14
<Page>

     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 U.S. Congress will continue.

     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 may maintain 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

                                       15
<Page>

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.

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 the U.S. 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

                                       16
<Page>

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 7,700 square feet of office space in
Houston, Texas, at an annual rent of $205,104. The lease expires on
August 31, 2006, however the Company does have a right to terminate the lease on
or after September 1, 2004 by payment of two months rent. The Company leases
approximately 18,200 square feet of office space in Corpus Christi, Texas. The
annual rent is $179,304 and the primary leases expire on June 30, 2003. The
Company currently has more office space than it needs in Corpus Christi, and has
the option to sublet a portion of its office space.

EMPLOYEES

     The Company has 13 full-time employees in its Houston, Texas office and 29
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.

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 16,055 Mcf per day and 449 Bbls of oil per day for the year
ended December 31, 2000 and 17,967 Mcf per day and 362 Bbls of oil per day
for the year ended December 31, 2001. These properties combined with the
proceeds of sales of interests in certain of its exploration projects have
provided most of the Company's revenues to date.

NATURAL GAS AND OIL RESERVES

The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2001 and 2000, and the present values attributable
to these reserves at these dates. The reserve data and present values were
prepared by Ryder Scott Company L.P., independent petroleum engineering
consultants.

<Table>
<Caption>
                                                                            AT DECEMBER 31
                                                                         2001            2000
                                                                         ----            ----
     <S>                                                            <C>            <C>
     Net proved reserves:
        Natural gas (Mcf)                                             15,300,000      21,076,278
        Oil and condensate (Bbls)                                        507,457         454,498
        Total (Mcfe)                                                  18,344,742      23,803,266

     Standardized measure of discounted future net cash flows (1)   $ 26,076,494   $ 161,545,400
</Table>

     (1)  The standardized measure of discounted future net cash flows
          represents the present value of future net

                                       17
<Page>

          revenues after income tax discounted at 10% per annum and has been
          calculated in accordance with SFAS No. 69, "Disclosures About Oil and
          Gas Producing Activities" (see Note 10 -- Supplemental Natural Gas Oil
          Information (Unaudited)) and, in accordance with current SEC
          guidelines, and does not include estimated future cash inflows from
          our hedging program. The standardized measure of discounted future net
          cash flows attributable to our reserves was prepared using prices in
          effect at the end of the respective periods presented, discounted at
          10% per annum on a pre-tax basis. Average prices per Mcf of natural
          gas used in making the present value determinations as of December 31,
          2001 and 2000 were $2.31 and $10.44, respectively. Average prices per
          Bbl of oil used in making the present value determinations as of
          December 31, 2001 and 2000 were $18.45 and $28.73, respectively.

     In accordance with applicable requirements of the Securities and Exchange
Commission, we estimate our proved reserves and future net cash flows using
sales prices and costs estimated to be in effect as of the date we make the
reserve estimates. We hold the estimates constant throughout the life of the
properties, except to the extent a contract specifically provides for
escalation. Gas prices, which have fluctuated widely in recent years, affect
estimated quantities of proved reserves and future net cash flows. Any estimates
of natural gas and oil reserves and their values are inherently uncertain,
including many factors beyond our control. The reserve data contained in this
Annual Report on Form 10-KSB represent only estimates. Reservoir engineering is
a subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates of different
engineers, including those we use, may vary. In addition, estimates of reserves
may be revised based upon actual production, results of future development and
exploration activities, prevailing natural gas and oil prices, operating costs
and other factors, which revision may be material. Accordingly, reserve
estimates may be different from the quantities of natural gas and oil that we
are ultimately able to recover and are highly dependent upon the accuracy of the
underlying assumptions. Our estimated proved reserves have not been filed with
or included in reports to any federal agency.

DRILLING ACTIVITY

     From November 1, 1997 (the effective date of the Company's May 1998
acquisitions of project interests) through December 31, 1999, 53 exploratory
and developmental wells were drilled for the Company's account, of which 34
were completed and 19 were dry holes. In 2000, 41 exploratory and 11
developmental wells were drilled and logged for the Company's account of
which 31 were completed and 21 were dry holes. In 2001, 41 exploratory and
five developmental wells were drilled and logged for the Company's account of
which 26 were completed as of March 28, 2002, one of which was temporarily
abandoned, and 19 were dry holes.

     The following table sets forth certain information regarding the actual
drilling results for each of the years 2000 and 2001 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>
     2000
     ----
       Productive .............................      25       5.994        6        1.559
       Dry.....................................      16       5.275        5        1.412
     2001
     ----
       Productive..............................      23       7.068        4        0.569
       Dry.....................................      18       4.848        1        0.094
</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 April 9, 2002, the Company participated in the drilling of two
additional exploratory wells and one additional development well, of which
one had been completed, one of which was temporarily abandoned and one still
in progress.

                                       18
<Page>

PRODUCTIVE WELL SUMMARY

     The following table sets forth certain information regarding the Company's
ownership as of December 31, 2001 of productive gas and oil wells in the areas
indicated.

<Table>
<Caption>
                                                          GAS                  OIL
                                                  -------------------   --------------------
                                                   GROSS        NET      GROSS        NET
                                                  --------   --------   --------   ---------
     <S>                                             <C>      <C>          <C>       <C>
     Alabama ..................................       0            0       1         0.061
     Kansas ...................................       1        0.137       0             0
     Louisiana ................................       2        0.110       1         0.187
     Oklahoma..................................       2        0.002       2         0.226
     Texas.....................................      92       16.224       5         0.350
                                                  --------   --------   --------   ---------
       Total ..................................      97       16.473       9         0.824
                                                  ========   ========   ========   =========
</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
indicated.

<Table>
<Caption>
                                                                YEAR ENDED DECEMBER 31,
                                                             -----------------------------
                                                                 2001             2000
                                                             -------------   -------------
  <S>                                                        <C>             <C>
  Net Production:
     Oil (Bbl) ...........................................       132,165        163,892
     Gas (Mcf)............................................     6,557,949      5,860,195
     Gas equivalent (Mcfe)................................     7,350,939      6,843,547
  Average sales price:
     Oil ($ per Bbl)......................................   $     24.74(1)  $    32.34(1)
     Gas ($ per Mcf)......................................   $      4.38(1)  $     4.12(1)
  Average production expenses and taxes ($ per Mcfe)......   $      0.77     $     0.48
</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 $22.37 per Bbl and $3.89 per Mcf for the
       year ended December 31, 2001.

LEASEHOLD ACREAGE

     The following table sets forth as of December 31, 2001, 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           UNPROVEN
                            ----------------      UNDEVELOPED        --------
                                                  ----------
     STATE                 GROSS     NET         GROSS     NET     GROSS       NET
     -----                ------   -----        -------   ----   -------   -------
     <S>                  <C>      <C>              <C>    <C>   <C>        <C>
     Alabama..............   411       7             --     --     1,877        26
     Arkansas ............    --      --             --     --     6,360     2,544
     Kansas ..............   640      31             --     --        --        --
     Louisiana ...........   320      80             --     --     7,344       607
     Mississippi..........     0       0             --     --       760       549
     Oklahoma ............ 2,198      51             --     --    12,929     3,727
     Texas ...............34,951   7,108            320     36   100,670    31,283
                          ------   -----        -------   ----   -------   -------
          Total ..........38,520   7,277            320     36   129,940    38,736
                          ======   =====        =======   ====   =======   =======
</Table>

                                       19
<Page>

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.

                                       20
<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 was admitted to trading on the NASDAQ Small Cap
Market under the symbol "FNGC". 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. There were no
reported trades of the Series B Warrants subsequent to that time. The Series B
Warrants expired on August 8, 2001.

     On September 23, 1999, the Company acquired 3DX via a 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, the Company issued 356,999 shares of new
convertible preferred stock that could be redeemed at the Company'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 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 156 common
shareholders of record and 2,979 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, 2001       $3.19        $2.00
                 September 30, 2001       4.10         2.45
                 June 30, 2001            5.24         3.50
                 March 31, 2001           5.19         3.50

                 December 31, 2000       $5.19        $3.13
                 September 30, 2000       4.75         2.47
                 June 30, 2000            4.13         1.63
                 March 31, 2000           2.75         1.56
</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 the Company's operations for
the twelve month periods ended December 31, 2001 and 2000 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 actual results could
differ materially from those projected in such forward-looking statements. The
risks and uncertainties include

                                       21
<Page>

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 recent events, the impact of the successful efforts accounting
method as it relates to the certain acquisitions, and a survey of the Company's
history are as follows:

     RECENT EVENTS. On March 17, 2002, the Company and Santos entered into an
agreement providing for Santos' acquisition of all issued and outstanding common
stock of the Company by means of a tender offer at a price of US$2.84 per share
in cash and a follow-on merger at the same price. Under the terms agreed, Santos
initiated a formal offer on March 26, 2002. The offer must remain open through
at least April 22, 2002. It is conditioned upon the receipt of at least a
majority of the Company's outstanding shares. If Santos receives at least a
majority of such shares, it will, subject to various typical contingencies such
as the absence of any material adverse changes, close on the purchase of shares
tendered and then proceed to acquire all remaining outstanding shares through a
subsequent merger, the timing of which would be announced at a later date.
Shareholders who do not participate in the tender offer would also receive $2.84
per share in cash in the merger. At a meeting held on Saturday, March 16, 2002,
the Company's Board of Directors voted to accept and support the Santos tender
offer and voted to recommend that the Company's shareholders accept the cash
tender offer and approve the merger. In addition, as a condition to the offer,
two major shareholders and the chairman of the Board of Directors agreed to
tender all of the shares owned by them (representing 9,991,662 shares or 52% of
the Company's total outstanding shares) in the Santos tender offer and have
granted Santos the option to acquire all of their shares if the tender offer is
not consummated for certain reasons. In voting to accept and support the Santos
tender offer, the Company's Board of Directors considered a number of factors.
The Company has historically been forced to constrain capital spending and to
sell larger than desired interests in its exploration projects and prospects in
order to fund its capital program, which has resulted in lower than expected
reserve growth. As part of the Company's evaluation of strategic alternatives, a
process, initially undertaken in late 2000, the Board of Directors recognized
that its inability to access sufficient capital at an acceptable cost would be
an ongoing impediment to the Company's ability to fully exploit its sizable
asset base. The Company and it financial advisors do not anticipate a meaningful
improvement in the access to affordable capital in the foreseeable future, and
as a result it will be difficult to maximize the substantial reserve potential
that the Company believes exists in its prospect inventory. With this in mind,
and after revisiting strategic alternatives and potential transactions available
to the Company in the current marketplace, the Board of Directors recommended
that the Company's shareholders accept the Santos offer. In the event the tender
offer and merger are closed, the Company will not continue as a public company,
but will be a wholly owned subsidiary of Santos.

     The Company has also recently announced that its Poole #2 well has been
temporarily abandoned due to mechanical difficulties. The well, drilled on a
high potential feature, encountered several mud log shows and high-pressure gas
during drilling. The Company is encouraged by such indicators and anticipates
re-drilling the well.

CRITICAL ACCOUNTING POLICIES

     INTRODUCTION. The following describes the critical accounting policies used
by the Company in reporting its financial condition and results of operations.
In some cases, accounting standards allow more than one alternative accounting
method for reporting, such is the case with accounting for oil and gas
activities described below. In those cases, the Company's reported results of
operations would be different should it employ an alternative accounting method.

     SUCCESSFUL EFFORTS METHOD OF ACCOUNTING FOR OIL AND GAS ACTIVITIES. The
Securities and Exchange Commission ("SEC") prescribes in Regulation SX the
financial accounting and reporting standards for companies engaged in oil and
gas producing activities. Two methods are prescribed: the successful efforts
method and the full

                                       22
<Page>

cost method. Like many other oil and gas companies, the Company has chosen to
follow the successful efforts method. Management believes that this method is
preferable, as the Company has focused on exploration activities wherein there
are risks associated with future success, and as such earnings are best
represented by attachment to the drilling operations of the company.

Costs of successful wells, development dry holes and leases containing
productive reserves are capitalized and amortized on a unit-of-production basis
over the life of the related reserves. Estimated future abandonment and site
restoration costs, net of anticipated salvage values, are amortized on a unit of
production basis over the life of the related reserves. Other exploration costs,
including geological and geophysical expenses applicable to undeveloped
leasehold, 3-D seismic data, leasehold expiration costs and delay rentals are
expensed as incurred.

In accordance with accounting under successful efforts, the Company reviews
proved oil and gas properties for indications of impairment whenever events or
circumstances indicate that the carrying value of its oil and gas properties may
not be recoverable. When it is determined that an oil and gas property's
estimated future net cash flows will not be sufficient to recover its carrying
amount, an impairment charge must be recorded to reduce the carrying amount of
the asset to its estimated fair value. For the years ended December 31, 2001 and
2000, impairments of $4,514,077 and $4,771,272, respectively, were recognized.

     UNPROVED PROPERTY. Unproved properties, representing unproven leasehold
costs that are not being amortized pending evaluation of the respective
leasehold for future development, are assessed quarterly for impairment in
value, with any impairment charged to expense.

In addition, interests in twenty-eight exploration projects acquired in May
1998 were underdeveloped and were comprised primarily of interests in
unproven 3-D seismic based projects, which 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, 2001, the unamortized
balance was $1,641,900. In 2001 this amortization resulted in a $3,457,000
expense. The amortization of properties acquired pursuant to the May 1998
acquisitions will conclude in May of 2002.

     Impairments totaled $4,514,077 for the year-ended December 31, 2001.
Impairments were primarily related to unproved property costs on projects
which management believes have diminished value based upon 2001 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 into the
second quarter of 2002; 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.

     DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. In June 1998, Statement
of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" was issued. The Company
adopted SFAS No. 133, as amended, effective January 1, 2001. SFAS No. 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 be reported in other
comprehensive income ("OCI") to the extent the derivative is effective as a
hedge. 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 No. 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.

                                       23
<Page>

     RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. On June 29, 2001, SFAS No.
141, "Business Combinations" was approved by the Financial Accounting
Standards Board. SFAS No. 141 requires that the purchase method of accounting
be used or all business combinations initiated after June 30, 2001. The
Company was required to implement SFAS No. 141 on July 1, 2001. The adoption
of this statement had no effect on the Company's consolidated financial
position, cash flows or results of operations.

     On June 29, 2001, SFAS No. 142, "Goodwill and Other Intangible Assets",
was approved by the Financial Accounting Standards Board ("FASB"). SFAS No.
142 changes the accounting for goodwill from an amortization method to an
impairment-only approach. Amortization of goodwill, including goodwill
recorded in past business combinations, will cease upon adoption of this
statement. The Company was required to implement SFAS No. 142 on January 1,
2002. Management has reviewed SFAS No. 142 and determined that this statement
will not have a material effect on its consolidated financial position, cash
flows or results of operation.

     In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 provides the accounting requirements for retirement
obligations associated with tangible long-lived assets. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. The Company is currently assessing the new standard and has not yet
determined the impact on its consolidated financial position, cash flows or
results of operations.

     In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The new rules retain many of the fundamental recognition and
measurement provisions, but significantly change the criteria for classifying an
asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001. The Company is currently assessing the new standard and
has not yet determined the impact on its consolidated financial position, cash
flows or results of operations.

     NET OPERATING LOSS CARRY-FORWARDS. As a result of the tax rules applicable
to the acquisitions made in May of 1998, the Company may 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. 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. 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.

                                       24
<Page>

     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 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 the Company's common stock for 3.25 shares of 3DX common stock; or (ii) the
issuance of a new Company convertible preferred stock at a ratio of one share of
the Company's 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 the Company's common stock and
approximately 9% were converted into the Company's convertible preferred stock.
As a result, the Company 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 the Company'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. The Company added 19.256 billion cubic
feet equivalent ("BCFE") of new gas and oil reserves from its 2000 drilling
activities. 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.

OVERVIEW OF 2001 ACTIVITIES. The Company entered 2001 expecting to continue to
expand its production and reserves via exploration activities on its
technology-enhanced projects. By utilizing capital available to it from
operating cash flow, financing and industry partner transactions, the Company
continued to pursue an aggressive exploration budget in its major trends of
activity.

                                       25
<Page>

     The Company participated in working interests in 45 wells which reached
total depth and were logged in 2001. Its net production increased slightly from
6,843,547 net Mcfe in 2000 to 7,350,939 in 2001. Its net proven reserves as of
December 31, 2001, totaled 18.3 Bcfe down from 23.8 Bcfe at year-end 2000. The
decrease was primarily attributable to sales of project interests which totaled
8.3 net Bcfe. The Company focused its exploratory drilling on higher risk, high
potential return prospects and delineation drilling on its Runnells and Hordes
Creek Fields. Success in the Runnells Field, as evidenced by the Runnells #5 and
#7 wells drilled in 2001, substantially increased proven reserves during the
year; however, the Company sold approximately 71% of its interest in the
Runnells Field in the fourth quarter of 2001 for net proceeds of $20.3 million
plus reimbursement of previously incurred cost on the Runnells #7 well
attributable to the interests sold. Accordingly, the net reserve increases
attributable to the delineation of the field were not reflected in year-end net
reserve totals. Delineation of the Hordes Creek Field has proceeded at a limited
pace. The Pierra Childrens Trust #3 well did not successfully expand the field.
Further delineation drilling is expected in the Hordes Creek Field in 2002.

     The Company continues to believe it remains positioned to expand its net
proven reserves in 2002 via continued exploratory, delineation, and development
drilling. It believes that the rate of expansion will likely be proportionate to
the capital available to fund such activities. In the event the pending merger
as set forth in the Santos agreement does not close, the Company will continue
its business as historically conducted. It will also continue to look for
opportunities to consolidate business activities with an industry partner such
that more capital resources may be deployed to maximize the potential of its
Exploration Projects.

     In 2001 the Company also completed an amendment of its credit facility with
Deutsche Bank. As of year-end 2001, the amended facility provides for the bank
to loan up to $38,500,000 in two tranches. Tranche A is in the amount of
$30,000,000 with $13,500,000 established as the borrowing base and $7,689,071
outstanding at December 31, 2001. Tranche A will mature on August 13, 2002, at
which time it will convert to a four year quarterly amortizing term loan.
Tranche B is in the current amount of $8,500,000, of which the entire amount was
outstanding at December 31, 2001. It is payable interest only until due on
August 13, 2003, at which time the entire Tranche B balance is due.

     As of March 28, 2002, the Company has 19,140,667 total shares of common
stock outstanding. It employs 42 full time employees, including six in its
exploration and geophysical departments, six in its operations department, three
in its exploitation department, and nine in its land department. Its focus
continues to be the implementation of its business strategy as set forth in this
section.

COMPARISON OF 2001 TO 2000

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.

<Table>
<Caption>
                                                                  YEAR ENDED DECEMBER 31,
                                                             ----------------------------------
                                                                   2001                2000
                                                             -----------------   --------------
<S>                                                          <C>                 <C>
Net Production:
         Oil (Bbl) ....................................          132,165             163,892
         Gas (Mcf) ....................................        6,557,949           5,860,195
         Gas equivalent (Mcfe) ........................        7,350,939           6,843,547
Average sales price:
         Oil ($ per Bbl)...............................      $     24.74(1)      $     32.34(1)
         Gas ($ per Mcf) ..............................      $      4.38(1)      $      4.12(1)
Average production expenses and taxes ($ per Mcfe).....      $      0.77         $      0.48
</Table>

                                       26
<Page>

(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 $22.37 per Bbl and $3.89 per Mcf for the year ended
    December 31, 2001.

REVENUES. Total revenues increased 20% from $34,674,753 for the year ended
December 31, 2000 to $41,661,926 for the year ended December 31, 2001. The
primary reason for the increase was an increase in gain on sale of assets from
$9,329,631 in 2000 to $16,227,756 in 2001. Gas and oil revenues increased in the
period from $29,446,832 in 2000 to $31,942,264 in 2001. The overall change was
the result of all of the factors listed and discussed below.

     GAS AND OIL REVENUES. Total gas and oil revenues increased 8% from
$29,446,832 reported in 2000 to $31,942,264 in 2001. The increase in gas and oil
revenue was attributed mainly to increases in quantities of natural gas produced
net to the Company's account combined with increases in the prices for which
said production was sold, partially offset by a reduction in oil production and
differences in prices. Volumes increased 7% from 6,843,547 MCFE produced in 2000
to 7,350,939 MCFE in 2001. The average price received per barrel of oil sold
decreased from $32.34 in 2000 to $24.74 in 2001. The average price received per
MCF of natural gas sold increased from $4.12 in 2000 to $4.38 in 2001.

     GAIN ON SALE OF ASSETS. There was an increase of 74% in gain on sale of
assets of $6,898,125 from $9,329,631 reported in 2000 to $16,227,756 in 2001.
This was primarily attributable to the 2001 fourth quarter gain on the sale of a
portion of the Company's interest in the Runnells Field to an industry partner
of approximately $15,600,000. The gain on sale of assets in 2000 of $9,329,631
was attributable to sales of interests to industry partners in certain of
Company's projects. The largest components of the total in 2000 were a
$6,607,211 gain on the sale of interests in the Company's 3-D seismic
Raymondville Project and a gain of $1,797,707 recognized in conjunction with a
sales transaction with an interest in a 3-D seismic project overlying the
Company's Papalote Project area.

     OPERATING FEES. Operating fees increased due to increases in the number of
both exploratory and developmental wells operated, which has resulted in the
increase of operating fees of 59% from $454,016 for the year ended 2000 to
$722,388 for the year ended 2001.

     REALIZED LOSS ON COMMODITY TRANSACTIONS. The Company reduced by 26% its
realized losses from various commodity hedges by $1,258,249 to a realized loss
of $3,584,123 for the year ending 2001 as compared to a realized loss of
$4,842,372 for the same period in 2000. The gains or losses realized are
primarily attributable to various transactions in which the Company hedged
future gas and oil delivery obligations. The losses realized during 2000 and
2001 were incurred as average spot market prices for the period exceeded the
average hedge prices.

     UNREALIZED LOSS FROM HEDGING ACTIVITIES. The non-cash loss from hedging
activities is incurred as a result of the implementation of SFAS 133 on
January 1, 2001. There was no comparable entry in 2000. The non-cash loss of
$3,838,344 in 2001 resulted primarily from the required accounting treatment
applicable to the restructuring of a natural gas hedge at $2.45 per MMBtu on
January 25, 2001. The restructured portion of the hedge covered 5,000 MMBtu per
day of natural gas from February 2001 through December 2001. The $2.45 per MMBtu
hedge was restructured as a collar with a $3.25 put or floor and a $4.00 call or
cap on volumes ranging from 7,500 to 8,000 MMBtu per day in 2001, 7,000 to 8,500
MMBtu per day in 2002 and volumes of 4,500 MMBtu per day in 2003. The result
served to increase actual cash available in 2001. SFAS No. 133 treatment
requires the amortization of non-cash charges equal to the mark-to-market value
of the hedge as it existed before the restructure. In this case, a non-cash loss
will be recognized over the life of the hedge before it was restructured. This
procedure resulted in a non-cash loss of $6,818,598 in 2001. Non-cash credits to
income will be recognized over the life of the collar as restructured, which is
in the period February 2001 through December 2003. For the year ended
December 31, 2001, the unrealized gain on the collar was $2,980,254.

     OTHER REVENUES. The Company had other revenues of $191,985 for the year
2001 as compared with $286,646 for the year of 2000. This decrease was primarily
due to normal variances of various nominal accounts.

COSTS AND EXPENSES. Total costs and expenses decreased 3% from $43,335,391 in
2000 to $41,827,742 in 2001. The most significant changes relate to various
facets of increased production volumes and variances in exploration

                                       27
<Page>

activity. Increased production volumes resulted in increases in lease operating
expense and depletion as more fully described below. Exploration activities
resulted in decreases 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 2001. Other changes in costs and expenses are described
below.

     AMORTIZATION OF UNPROVED PROPERTIES decreased 33% to $3,457,000 in 2001
from $5,176,100 for 2000. The Company is amortizing the undeveloped and
unevaluated value of the properties acquired pursuant to an acquisition of
underdeveloped projects in May of 1998 over a period not to exceed forty-eight
months. The 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 2001 is the result of the reductions in
the size of the amortization pool in 2001 as compared to 2000. As of December
31, 2001, a $1,641,900 balance remained in this amortization pool. (Also see
Overview - Successful Efforts Accounting and Related Matters.)

     IMPAIRMENT OF GAS AND OIL PROPERTIES was $4,514,077 in 2001 compared to
$4,771,272 in 2000. 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. Impairment decreases of
5% in 2001 were primarily the result of third quarter impairments recognized on
several project areas as a result of recent evolving understandings of the
project areas. Included in these impairments were charges in the Lovell Lake, S.
Louisiana Eocene, Cheek, Gillock, Powderhorn South Field Trend and Hackberry
Trend projects.

     EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL decreased 97% from
$4,613,603 for 2000 to $148,469 for 2001. These exploration costs reflect 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 has required the acquisition and interpretations 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. Differences between 2000 and 2001
costs are primarily attributable to the Company's focus on exploitation of its
existing 3-D data in 2001.

     EXPLORATION COSTS - DRY HOLE was $6,307,129 for 2001 compared to $7,114,950
for 2000. This 11% decrease is attributable to drilling fewer dry holes. The
change reflects normal variance of such costs.

     GENERAL AND ADMINISTRATIVE EXPENSES increased 26% from $7,187,619 for 2000
as compared to $9,031,273 for 2001. The cost increases were primarily
attributable to the Company's active drilling program. This was also the result
of systems implementation costs and of additional personnel and personnel
upgrades. Management believes the upgrades can lead to better reporting and
greater efficiency and can lead to reductions in general and administrative cost
in 2002. Additionally, the estimated cost of a company wide bonus to be paid in
2002 of approximately $750,000 was accrued in 2001, whereas no bonus was accrued
in 2000.

     DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 5% from
$9,635,671 for 2000 to $10,136,584 in 2001. 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 2001. Downward reserve
revisions in late 2001 regarding the Company's Hackberry production increased
the unit costs of depletion in the Hackberry in 2001. (Also see Overview -
Overview of 2001 Activities.)

     INTEREST EXPENSE increased 61% from $1,361,533 for 2000 to $2,185,777 for
2001. 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 portion of its interest associated with ongoing projects,
of which capitalized amounts totaled $219,197 and $288,584 for the respective
years ending 2000 and 2001.

                                       28
<Page>

     PRODUCTION TAXES decreased 5% from $2,107,093 for 2000 to $1,999,759 for
2001. The decrease in production taxes was the result of further refinement of
the company's ongoing analysis of production activity as it relates to severance
taxes and to rebates paid by the state of Texas which were credited to 2001
production taxes.

     LEASE OPERATING EXPENSE increased 211% from $1,172,590 for 2000 to
$3,649,199 for 2001. The increase in lease operating expenses relates primarily
to an increase in the number of producing wells, salt water disposal fees and
processing fees.

     PROVISIONS FOR INCOME TAX. In 2001 the Company incurred Alternative Minimum
Federal Income Taxes totaling $291,418 which resulted from a partial sale of
interest in the Runnells Field to an industry partner in the fourth quarter of
2001. There were no events in 2000 that triggered Alternative Minimum Taxes.

     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 2001.

     NET LOSS PER COMMON SHARE decreased from a net loss of $0.40 per share for
2000 to $0.02 per share for 2001. Due to the factors discussed above, there was
a $7,077,370 decrease in net loss applicable to common stockholders for the
twelve months ended December 31, 2001. The increase of weighted average number
of common equivalent shares at December 31, 2001 of approximately 172,000 shares
as compared to 2000 also affected the per share calculations. Approximately
19,049,454 weighted average common equivalent shares were outstanding at
December 31, 2001 as compared with approximately 18,877,192 at December 31,
2000.

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 its exploration
projects.

     Management continues to believe these projects represent some of the most
promising prospects in the Company's history. Production from wells drilled from
1998 through the present on its Exploration Projects has substantially increased
the Company's revenues. Net growth of production in 2001 was less than expected.
Net proven gas and oil reserves at year-end 2001 declined as compared with
year-end 2000. This was due to sales of proven reserves pursuant to sales to
industry partners during 2001, slower then anticipated delineation drilling on
proven fields, and the absence of a major discovery in 2001. These factors have
also resulted in reduced production in the first quarter of 2002 as compared to
the first quarter of 2001. Net production is expected to increase in the second
quarter of 2002 as new wells come on line. The Company believes that continued
exploratory and delineation drilling on its exploration projects will yield a
resumption of the growth trends in both net production and net gas and oil
reserves evidenced in 1998, 1999, and 2000. Conversely, the capital expenditures
planned in 2002 will continue to require substantial outlays of capital to
explore, develop and produce. The Company cannot fund its planned capital budget
from operating cash flow and will continue to seek supplemental sources from
industry partners, mezzanine debt, or other sources. The total 2002 capital
budget is being reviewed and will likely be reduced to a range of from $15
million to $20 million.

     Closing of the pending tender offer of Santos and the subsequent merger
could cause the Company to become a wholly owned subsidiary of Santos in the
second quarter of 2002.

LIQUIDITY AND CAPITAL RESOURCES

     The Company business plan provides for substantial investment in drilling,
completion, land and seismic. The budgeted amounts are based upon exploration
opportunities and are periodically adjusted based upon available capital, new
opportunities and industry conditions. The 2002 budget was initially anticipated
to approach $26 million, about 20% of which was for new seismic data and
investment in new projects. This is currently being reviewed and is anticipated
to be reduced to a total of $15 million to $20 million. Investment in planned
new seismic will be the area most effected as such plans will likely be deferred
until 2003. The Company's sources of financing its capital budget, include
borrowing capacity under its credit facilities, the sale of promoted interests
in the Exploration Projects to industry partners and cash provided from
operations.

                                       29
<Page>

     The Company entered 2002 having grown from $1,372,000 in total 1998 gas and
oil production revenues and operating cash flow deficits to a company with over
$31,900,000 in gas and oil revenues and $11,700,000 in operating cash flow (net
income less gain on sale of assets plus non-cash expenses, as calculated before
capital expenditures for drilling and completion and new 3-D seismic data
acquisition costs) in 2001. Due to the sales of interests in the Runnells Field
in the fourth quarter of 2001, first quarter 2002 net production volumes are
less than first quarter 2001. Additional drilling success in 2002 could allow
the Company to resume the trend of increasing production. This would allow the
Company to achieve 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. Lack of drilling success in
the first half of 2002 would increase the Company's dependence on external
sources of funds to supplement its capital budget in the second half of 2002.

     The Company ended 2001 with a deficit working capital of approximately
$4.4 million. Of this amount approximately $0.5 million was represented by
the current portion of its long-term debt. The Company's borrowing base
pursuant to Tranche A was set at $13,500,000 in the fourth quarter of 2001.
Pursuant to the total Deutsche Bank credit facility, $22 million is now
available of which $16,189,071 had been drawn as of December 31, 2001. It is
currently comprised of two tranches; $13.5 million is currently available
under Tranche A of which $7,689,071 had been drawn as of December 31, 2001
and $8.5 million under Tranche B of which the entire amount had been drawn as
of December 31, 2001. Tranche A is a revolving facility with no required
principal payments until 2002, at which time it converts into a four-year
term loan. The term loan would be amortized in quarterly payments beginning
the fourth quarter of 2002. Tranche B is payable interest only until due on
August 13, 2002, at which time the entire balance is due. Both loans are at a
varied interest rate utilizing either Deutsche Bank's alternative interest
rate or the London interbank rate plus 2% for Tranche A and plus 6% for
Tranche B. As of March 28, 2002, $10.2 million was drawn under Tranche A and
$8.5 million under Tranche B. All undrawn funds will be available to
supplement working capital or 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. There also is 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 August 13, 2003, 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, and on August 13,
2001 a five year warrant to purchase an additional 125,000 shares of the
Company's common stock for $3.00 per share. The Company expects further
increases in the Tranche A borrowing base in the event its proven oil and gas
reserves grow. This 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 2002. There is, however,
no assurance said proven oil and gas reserve will grow. In the event reserves
decline in the first half of 2002 the borrowing base could be reduced which
will reduce capital available for exploration activities.

     Pursuant to the Company's credit agreement with Deutsche Bank, it has
certain covenants regarding current interest coverage ratios and other covenants
and restrictions 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 and restrictions in the year 2002, 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. Restrictions include limitations on
additional borrowing, sales of significant properties and payment

                                       30
<Page>

of dividends.

     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
2002, 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 2002. Second
quarter hedges are estimated to approximate 85% of the Company's natural gas
productions as additional developed wells come on line. Cash on hand, cash
available pursuant to the Deutsche Bank credit facility, and cash flow from
operations will contribute significantly to satisfaction of budget requirements
for 2002. These funds will have to be supplemented by the sale of project
interests to industry partners or by other sources of capital for the Company to
fully fund said budget. The Company expects to fund a substantial portion of its
2002 capital budget from its cash flow from operations. It projects meaningful
increases in net daily production in the second half of 2002 attributable to
projected drilling activity currently being conducted and planned throughout the
remainder of 2002. 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 reduced.

     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. In
the event the pending Santos tender offer and follow on merger do not close, the
Company will continue 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. The
Company will also consider potential mergers or other business and asset
consolidation opportunities. 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
through December 2002 natural gas production of 6,500 MMBtu/day at $2.90/MMBtu.
It also had a natural gas collar in place covering 8,500 MMBtu/day of first
quarter 2002 natural gas production and 8,000, 7,500, and 7,000 MMBtu/day of
second, third, and fourth quarter production respectively. The collar was
comprised of a $3.25 put or floor and a $4.00 call or cap. The natural gas
collar also covers 4,500 MMBtu/day of calendar year 2003 natural gas production.
The company has no oil volumes hedged.

     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 2002 hedges are estimated to approximate 95% of the
Company's natural gas and none of its oil production for such quarter. Future
percentages will vary.

     WORKING CAPITAL. At December 31, 2001, the Company had a cash balance of
$940,919, total current assets of $14,867,774, and total current liabilities of
$19,230,366. This resulted in a working capital deficit of $4,362,592. Were the
current portion of long-term debt due to Deutsche Bank AG not included in
current liabilities, the working capital deficit would have been $3,882,025. The
current portion of long term debt at December 31, 2001 was comprised of $480,567
of Tranche A debt due to Deutsche Bank in the fourth quarter of 2002. The
Company had $5,810,929 of available undrawn credit from Deutsche Bank at
December 31, 2001. Had said amounts been fully drawn the Company would have had
a small working capital surplus. The Company expects that in the second half of
2002 it will resume its trend of increasing gas and oil revenues and 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

                                       31
<Page>

net working capital will be negatively effected by the Company's continuing
aggressive capital expenditures program on its Exploration Projects. It could
also be negatively effected by any 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 intends to aggressively pursue its exploration
activity on its technology-enhanced projects. 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 growth in its proven natural gas and oil reserves in 2002. The Company
expects to fund significant portions of its year 2002 exploration budget from
operating cash flow (prior to capital expenditures and new 3-D seismic data
acquisition costs). 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 project interests to industry
partners, as it seeks to maximize its interests and manage its risks while
aggressively pursuing its exploration projects. The Company recognizes that it
will be difficult to internally generate the total capital desired to maximize
the exploration and development opportunities inherent in its expansive
inventory of Exploration Projects. Accordingly if the pending Santos tender
offer and follow on merger does not proceed to closing, the Company will work to
seek out acquisition, merger an other asset consolidation opportunities which
may lead to a larger capital structure and greater administrative economies of
scale.

                                       32
<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, 2001 and
2000, and the related consolidated statements of operations, stockholders'
equity and comprehensive income 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, 2001 and 2000, 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.

As described in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for derivative and hedging instruments in
accordance with Statement of Financial Accounting Standards No. 133 "Accounting
for Derivative and Hedging Instruments".

Deloitte & Touche LLP
Houston, Texas

April 12, 2002

                                       33
<Page>

                            ESENJAY EXPLORATION, INC.
                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<Table>
<Caption>
                                                                    DECEMBER 31,       DECEMBER 31,
                                                                       2001               2000
                                                                   ---------------   ---------------
<S>                                                                 <C>               <C>
Current assets:
    Cash and cash equivalents...................................    $     940,919     $   3,002,700
    Accounts receivable, net of allowance for doubtful
       accounts of $482,541 at December 31, 2001 and
       $445,872 December 31, 2000...............................        8,144,276         8,124,026
    Accounts receivable oil and gas sales.......................        1,665,570         6,135,807
    Receivables from affiliates.................................          360,182           124,268
    Inventory...................................................          911,445                --
    Prepaid expenses and other..................................        1,529,867         2,183,093
    Current portion of derivative assets........................        1,315,515                --
                                                                   ---------------   ---------------
             Total current assets...............................       14,867,774        19,569,894

Property and equipment, successful efforts method of
       accounting...............................................       97,871,396        81,977,022
Less: accumulated depletion, depreciation,
     amortization and impairments...............................      (49,329,061)      (40,087,050)
                                                                    --------------   ---------------
             Total property and equipment, net..................       48,542,335        41,889,972

Long-term derivative assets.....................................        1,013,352                --
Other assets  ..................................................        1,167,911           903,208
                                                                   ---------------   ---------------
             Total assets.......................................    $  65,591,372     $  62,363,074
                                                                   ===============   ===============
</Table>

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

                                       34
<Page>

                            ESENJAY EXPLORATION, INC.
                           CONSOLIDATED BALANCE SHEETS

                      LIABILITIES AND STOCKHOLDERS' EQUITY

<Table>
<Caption>
                                                                    DECEMBER 31,      DECEMBER 31,
                                                                        2001              2000
                                                                   ---------------   ---------------
<S>                                                                 <C>               <C>
Current liabilities:
    Accounts payable............................................    $  10,757,508     $   6,450,723
    Accounts payable to affiliate...............................              ---           269,835
    Revenue distribution payable................................        3,718,126         6,101,354
    Current portion of long-term debt...........................          480,567         6,750,000
    Accrued, deferred and other liabilities.....................        3,865,503         4,687,855
    Current portion of derivative liabilities...................          408,662               ---
                                                                   ---------------   ---------------
             Total current liabilities..........................       19,230,366        24,259,767

Long-term debt .................................................       15,708,504        13,591,782
                                                                   ---------------   ---------------
             Total liabilities .................................       34,938,870        37,851,549

Stockholders' equity:
    Common stock:
       Class A common stock, $.01 par value; 40,000,000
       shares authorized; and 19,108,345 and 18,958,477
       outstanding at December 31, 2001 and  December 31, 2000,
       respectively.............................................          191,083           189,585
    Additional paid-in capital .................................       85,446,449        84,699,705
    Stock subscription receivable...............................          (14,640)         (106,060)
    Accumulated other comprehensive income......................        5,758,549               ---
    Accumulated deficit.........................................      (60,728,939)      (60,271,705)
                                                                   ---------------   ---------------
             Total stockholders' equity.........................       30,652,502        24,511,525
                                                                   ---------------   ---------------
             Total liabilities and stockholders' equity.........    $  65,591,372     $  62,363,074
                                                                   ===============   ===============
</Table>

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

                                       35
<Page>

                            ESENJAY EXPLORATION, INC.

                      CONSOLIDATED STATEMENTS OF OPERATIONS

<Table>
<Caption>
                                                                          Year Ended December 31,
                                                                     ----------------------------------
                                                                           2001              2000
                                                                     ---------------   ----------------
<S>                                                                  <C>               <C>
Revenues:
    Gas and oil revenues...........................................  $  31,942,264     $   29,446,832
    Realized loss on commodity transactions........................     (3,584,123)        (4,842,372)
    Unrealized loss from hedging activities........................     (3,838,344)                --
    Gain on sale of assets.........................................     16,227,756          9,329,631
    Operating fees.................................................        722,388            454,016
    Other revenues.................................................        191,985            286,646
                                                                     ---------------   ----------------
             Total revenues........................................     41,661,926         34,674,753
                                                                     ---------------   ----------------

Costs and expenses:
    Lease operating expense........................................      3,649,199          1,172,590
    Production taxes...............................................      1,999,759          2,107,093
    Depletion, depreciation and amortization.......................     10,136,584          9,635,671
    Amortization of unproved properties............................      3,457,000          5,176,100
    Impairment of oil and gas properties...........................      4,514,077          4,771,272
    Exploration costs-geological and geophysical...................        148,469          4,613,603
    Exploration costs-dry hole.....................................      6,307,129          7,114,950
    Interest expense...............................................      2,185,777          1,361,533
    Other expenses.................................................        398,475            194,960
    General and administrative.....................................      9,031,273          7,187,619
                                                                     ---------------   ----------------
             Total costs and expenses..............................     41,827,742         43,335,391

Loss before provision for income taxes and extraordinary gain......       (165,816)        (8,660,638)
Benefit (provision) for income taxes...............................       (291,418)                --
                                                                     ---------------   ----------------
Net loss  before extraordinary gain................................       (457,234)        (8,660,638)
Extraordinary gain.................................................             --          1,126,034
                                                                     ---------------   ----------------
Net loss attributable to common stockholders.......................  $    (457,234)    $   (7,534,604)
                                                                     ===============   ================

Net loss per share of common stock:
    Basic and diluted:
       Net loss before extraordinary gain attributable
            to common stockholders.................................  $       (0.02)    $        (0.46)
       Extraordinary gain..........................................                              0.06
                                                                     ---------------   ----------------
       Net loss attributable to common
            shareholders...........................................  $       (0.02)    $        (0.40)
                                                                     ===============   ================

Weighted average number of common shares outstanding...............     19,049,454         18,877,192
                                                                     ===============   ================
</Table>

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

                                       36
<Page>

                            ESENJAY EXPLORATION, INC.

                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                            AND COMPREHENSIVE INCOME

<Table>
<Caption>

                                  Preferred                 Class A              Additional
                                    Stock                Common Shares            Paid-in        Stock        Accumulated
                             --------------------   ------------------------      Capital     Subscription     Deficit
                              Shares      Amount       Shares       Amount                     Receivable
                             --------   ---------   -----------   ----------   ------------   ------------   ------------
<S>                          <C>        <C>          <C>          <C>          <C>            <C>            <C>
Balance,
January 1, 2000...........    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 subscription....         --          --        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)
                             ========   =========   ===========   ==========   ============   ============   ============

Issuance of warrants......         --          --            --           --        150,700             --             --
Issuance of common
  stock...................         --          --       149,868        1,498        596,044             --             --
Payment of stock
  subscription
  receivable..............         --          --            --           --             --         91,420             --
Issuance of common stock
  through subscriptions...         --          --            --           --             --             --             --

Net loss..................         --          --            --           --             --             --   $   (457,234)

Cumulative effect of
  change in accounting
  principle...............         --          --            --           --             --             --             --

Change in fair value of
  derivative hedging
  instruments.............         --          --            --           --             --             --             --

Hedge settlements
  re-classified to income.         --          --            --           --             --             --             --

Total comprehensive
  income..................         --          --            --           --             --             --             --
                             --------   ---------   -----------   ----------   ------------   ------------   ------------

Balance,

  December 31, 2001.......         --          --    19,108,345   $  191,083   $ 85,446,449   $    (14,640)  $(60,728,939)
                             ========   =========   ===========   ==========   ============   ============   ============

<Caption>

                              Accumulated
                                Other            Total
                             Comprehensive   Stockholders'
                                Income          Equity
                             -------------   -------------
<S>                          <C>             <C>
Balance,
January 1, 2000...........              --   $  32,332,750

Issuance of warrants......              --         110,000

Redemption of preferred
  stock...................              --        (687,225)
Issuance of common
  stock...................              --         217,404
Payment of stock
  subscription
  receivable..............              --          73,200
Issuance of common stock
  through subscription....              --              --
 Net loss.................              --      (7,534,604)
                             -------------   -------------

 Balance,

  December 31, 2000.......              --   $  24,511,525
                             =============   =============

Issuance of warrants......              --         150,700
Issuance of common
  stock...................              --         597,542
Payment of stock
  subscription
  receivable..............              --          91,420
Issuance of common stock
  through subscriptions...              --              --

Net loss..................              --        (457,234)

Cumulative effect of
  change in accounting
  principle...............     (14,909,492)             --

Change in fair value of
  derivative hedging
  instruments.............      24,506,385              --

Hedge settlements
  re-classified to income.      (3,838,344)             --

Total comprehensive
  income..................              --       5,301,315
                             -------------   -------------

Balance,

  December 31, 2001.......   $   5,758,549   $  30,195,268
                             =============   =============
</Table>

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

                                       37
<Page>

                            ESENJAY EXPLORATION, INC
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                                                Year Ended December 31,
                                                                           --------------------------------
                                                                               2001                2000
                                                                           -------------       ------------
<S>                                                                        <C>                 <C>
Cash flows from operating activities:
   Net loss                                                                $    (457,234)      $ (7,534,604)
   Adjustments to reconcile net loss to net cash
     provided by (used in) operating activities:
        Depletion, depreciation and amortization .....................        10,136,584          9,635,671
        Amortization of unproven property.............................         3,457,000          5,176,100
        Impairment of oil and gas properties..........................         4,514,077          4,771,272
        Exploration costs - dry hole..................................         6,307,129          7,114,950
        Unrealized loss from hedging activities.......................         3,838,344                 --
        Gain on sale of assets........................................       (16,227,756)        (9,329,631)
        Extraordinary gain............................................                --         (1,126,034)
   Changes in operating assets and liabilities:
        Trade and affiliate receivables...............................         4,214,072         (6,942,964)
        Prepaid expenses..............................................           653,226          1,757,040
        Other assets..................................................          (439,684)          (136,568)
        Inventory.....................................................          (911,445)                --
        Trade and affiliate payables..................................         4,036,950         (4,201,984)
        Revenue distribution payable..................................        (2,383,228)         3,609,556
        Accrued, deferred and other liabilities.......................          (822,352)        (1,407,333)
                                                                           -------------       ------------
        Net cash provided by operating activities.....................        15,915,683          1,385,471
                                                                           -------------       ------------

Cash flows from investing activities:
   Capital expenditures - gas and oil properties......................       (36,061,944)       (19,254,789)
   Capital expenditures - other property and equipment................          (533,344)          (183,013)
   Proceeds from sale of assets.......................................        21,930,873         14,362,776
                                                                           -------------       ------------
      Net cash used in investing activities...........................       (14,664,415)        (5,075,026)
                                                                           -------------       ------------

Cash flows from financing activities:
   Proceeds from issuance of debt.....................................        18,908,217         20,341,782
   Repayments of long-term debt.......................................       (23,060,928)       (15,964,523)
   Preferred stock redeemed...........................................                --           (683,655)
   Proceeds from issuance of warrants.................................           150,700            110,000
   Net proceeds from issuance of common stock.........................           471,421            217,404
   Proceeds from exercise of stock options............................           126,121                 --
   Payment of stock subscriptions receivables.........................            91,420             73,200
                                                                           -------------       ------------
      Net cash (used in) provided by financing activities.............        (3,313,049)         4,094,208
                                                                           -------------       ------------

   Net change in cash and cash equivalents............................        (2,061,781)           404,653

Cash and cash equivalents at beginning of year........................         3,002,700          2,598,047
                                                                           -------------       ------------

Cash and cash equivalents at end of year..............................     $     940,919       $  3,002,700
                                                                           =============       ============

Supplemental disclosure of cash flow information:
   Cash paid for interest.............................................     $   1,942,274       $  1,372,124
Supplemental disclosure of non cash investing and
   and financing activities:
   Issuance  of common  stock for 401(k)  matching,  bonuses and stock
   subscriptions......................................................     $     132,354       $     69,460
</Table>

                                       38
<Page>

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

                                       39
<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 and are
depleted by the unit of production method based upon estimated proved
reserves. 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. On the sale or retirement of a complete unit of a
proved property, the cost and related accumulated depreciation, depletion,
amortization and impairment are eliminated from the property accounts, and
the resultant gain or loss is recognized. On the retirement or sale of a
partial unit of proved property, the cost is charged to accumulated
depreciation, depletion, amortization and impairment with a resulting gain or
loss recognized in income. On the sale of an entire interest in an unproved
property for cash or cash equivalent, gain or loss on the sale is recognized,
taking into consideration the amount of any recorded impairment if the
property had been assessed individually. If a partial interest in an unproved
property is sold, the amount received is treated as a reduction of the cost
of the interest retained.

     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
$4,514,077 and $4,771,272 of impairment charges during 2001 and 2000,
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, is being amortized on a straight-line basis over a period not to
exceed forty-eight months. Such amortization was $3,457,000 and $5,176,100 for
the years ended December 31, 2001 and 2000, respectively. The balance in this
amortizing group of unproven properties was $1,641,900 and $5,334,700 at
December 31, 2001 and 2000, respectively.

                                       40
<Page>

     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
carry-forwards, and tax credit carry-forwards.

     COMMODITY TRANSACTIONS - The Company attempts to minimize the price risk of
a portion of its future oil and gas production with commodity futures contracts.
Prior to January 1, 2001, gains and losses on these contracts were recognized in
the period in which revenue from the related gas and oil production was recorded
or when the contracts were closed. To the extent that the quantities hedged
under the commodity transaction exceeded current production, the Company
recognized gains or losses on the overhedged amount. This policy was changed as
of January 1, 2001.

     In June 1998 Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities" was issued. The
Company adopted SFAS No. 133, as amended, effective January 1, 2001. SFAS No.
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") to
the extent the derivative is effective as a hedge. 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 No. 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.

     CAPITALIZED INTEREST - The Company capitalizes interest costs incurred on
exploration projects. Interest capitalized for the years ended December 31, 2001
and 2000 was approximately $288,584 and $219,197, 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, 2001 and 2000 was a liability of approximately 149,182 MCF or
$272,885 and 135,676 MCF or $245,719, respectively.

     EXPLORATION COSTS - The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. In 2001
and 2000, the Company expensed $148,469 and $4,613,603 respectively in
geological and geophysical costs and $6,307,129 and $7,114,950 respectively in
dry hole costs. 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 - SFAS 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

                                       41
<Page>

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 were not recorded in the consolidated
financial statements to the extent the swaps qualify for hedge accounting prior
to January 1, 2001. This policy was changed as of January 1, 2001 when the
Company adopted SFAS No. 133.

     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, 2001 and 2002 all potentially diluted securities are anti-dilutive and
therefore are not included in the earnings per share calculation. Such
potential common shares were 1,017,435 and 766,917 for the years ended
December 31, 2001 and 2000, respectively.

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

<Table>
<Caption>
                                                                        2001              2000
                                                                   -------------     ------------
<S>                                                                <C>               <C>
BASIC AND DILUTED EARNINGS PER SHARE
 Weighted average common shares outstanding ...................      19,049,454        18,877,192
                                                                   ============      ============
 Basic and diluted loss per share before extraordinary gain ...    $      (0.02)     $      (0.46)
                                                                   ============      ============
 Basic and diluted loss per share .............................    $      (0.02)     $      (0.40)
                                                                   ============      ============
EARNINGS FOR BASIC AND DILUTED COMPUTATION
 Net loss to common stockholders before extraordinary gain ....    $   (457,234)     $ (8,660,638)
 Extraordinary gain ...........................................              --         1,126,034
                                                                   ------------      ------------
 Net loss to common stockholders (basic and
   diluted loss per share computation) ........................    $   (457,234)     $ (7,534,604)
                                                                   ============      ============
</Table>

     RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. On June 29, 2001, SFAS No.
141, "Business Combinations" was approved by the Financial Accounting
Standards Board ("FASB"). SFAS No. 141 requires that the purchase method of
accounting be used or all business combinations initiated after June 30,
2001. The Company was required to implement SFAS No. 141 on July 1, 2001. The
adoption of this statement had no effect on the Company's consolidated
financial position, cash flows or results of operations.

     On June 29, 2001 SFAS No. 142, "Goodwill and Other Intangible Assets",
was approved by the FASB. SFAS No. 142 changes the accounting for goodwill
from an amortization method to an impairment-only approach. Amortization of
goodwill, including goodwill recorded in past business combinations, will
cease upon adoption of this statement. The Company is required to implement
SFAS No. 142 on January 1, 2002. Management has reviewed SFAS No. 142 and
determined that this statement will not have a material effect on its
consolidated financial position, cash flows or results of operation.

     In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 provides the accounting requirements for retirement
obligations associated with tangible long-lived assets. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002, and early adoption is
permitted. The Company is currently assessing the new standard and has not yet
determined the impact on its consolidated financial position, cash flows or
results of operations.

                                       42
<Page>

     In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The new rules retain many of the fundamental recognition and
measurement provisions, but significantly change the criteria for classifying an
asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001. The Company is currently assessing the new standard and
has not yet determined the impact on its consolidated financial position, cash
flows or results of operations.

2.   RECENT EVENT:

     On March 17, 2002, the Company and Santos Americas and Europe Corporation
and ECM Acquisition Company, (collectively "Santos") entered into an agreement
providing for Santos' acquisition of all issued and outstanding common stock of
the Company by means of a tender offer at a price of US$2.84 per share in cash
and a follow-on merger at the same price. Under the terms agreed, Santos
initiated a formal offer on March 26, 2002. The offer must remain open through
at least April 22, 2002. It is conditioned upon the receipt of at least a
majority of the Company's outstanding shares. If Santos receives at least a
majority of such shares, it will, subject to various typical contingencies such
as the absence of any material adverse changes, close on the purchase of shares
tendered and then proceed to acquire all remaining outstanding shares through a
subsequent merger, the timing of which would be announced at a later date.
Shareholders who do not participate in the tender offer would also receive $2.84
per share in cash in the merger. At a meeting held on Saturday, March 16, 2002,
the Company's Board of Directors voted to accept and support the Santos tender
offer and voted to recommend that the Company's shareholders accept the cash
tender offer and approve the merger. In addition, as a condition to the offer,
two major shareholders and the Chairman of the Board of Directors agreed to
tender all of the shares owned by them (representing 9,991,662 shares or 52% of
the Company's total outstanding shares) in the Santos tender offer and have
granted Santos the option to acquire all of their shares if the tender offer is
not consummated for certain reasons.

3.   STOCKHOLDERS' EQUITY:

     In 2001 and 2000 the Company issued 149,868 and 120,778 additional
shares of common stock, respectively, pursuant to various employee options
which were exercised during the year, the Company's match of shares pursuant
to the Company's 401K plan and shares issued pursuant to a bonus plan.

     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 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, 2001 and 2000,
the Company had a common stock subscriptions receivable of $14,640 and $106,060
respectively outstanding related to these shares.

                                       43
<Page>

     WARRANTS - In August of 1998 the Company issued a warrant to purchase
191,250 shares of the Company's common stock at an exercise price of $7.20
per share. The warrant was issued in connection with the sale of common stock
of the Company. The warrant expires in August of 2002.

     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 was recorded in the amount of $110,000.

     In the third quarter of 2001, in conjunction with a restructuring of a
financing transaction, the Company issued warrants to purchase 125,000 shares
of the Company's common stock at an exercise price of $3.00 per share. The
warrants expire on August 3, 2006. The fair value of these warrants was
recorded at $150,700.

     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 2,546,836 shares of common stock at
prices ranging from $1.83 to $4.25 were outstanding as of December 31, 2001.

     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 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, 2001 and 2000.

<Table>
<Caption>
                                                              EMPLOYEE OPTION PLANS
                                               -----------------------------------------------------
                                                         2001                        2000
                                               ------------------------   --------------------------
                                                               WEIGHTED                     WEIGHTED
                                                               AVERAGE                      AVERAGE
                                                               EXERCISE                     EXERCISE
                                                 SHARES         PRICE        SHARES          PRICE
                                               ---------       --------   -----------       --------
     <S>                                       <C>             <C>        <C>               <C>
     Outstanding at beginning of year ........ 2,497,168       $   2.44     1,259,667       $   2.42
     Granted .................................   110,000           3.36     1,463,000           2.44
     Exercised ...............................   (48,497)          2.38       (66,499)          2.38
     Forfeited ...............................   (11,835)          2.38      (159,000)          2.38
     Outstanding at end of year .............. 2,546,836           2.48   $ 2,497,168       $   2.44

     Weighted average fair value of
      options granted during the year ......                   $   1.98                     $   1.51
                                                               --------                     --------
</Table>

Options outstanding at December 31, 2001 consisted of the following:

                                       44
<Page>

<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 - $4.25   2,546,836         $2.48            7.57 years           2,046,067           $2.49
</Table>

     The Company accounts for employee stock-based compensation arrangements in
accordance with the provisions of Accounting Principles Board Opinion No. 25
"Accounting for Stock Issued to Employees" and applies the disclosure-only
provisions of SFAS 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 2001 and 2000
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>
                                                                       2001              2000
                                                                  ------------      -----------
<S>                                                               <C>               <C>
Net loss attributable to common stockholders-as reported......... $   (457,234)     $(7,534,604)
Net loss attributable to common stockholders-pro forma...........   (1,657,274)      (8,531,852)
Net loss per common share-as reported............................        (0.02)           (0.40)
Net loss per common share-pro forma..............................        (0.09)           (0.45)
</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 52% and
82% in 2001 and 2000; risk-free interest rate of 4.03% and 5.95% in 2001 and
2000; 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 2001 and 2000. These sales resulted in an aggregate
gain of $16,227,756 in 2001 and $9,329,631 in 2000.

5.   LONG-TERM DEBT:

     Long-term debt consists of the following:

<Table>
<Caption>
                                                                                              DECEMBER 31,
                                                                                    ---------------------------------
                                                                                        2001               2000
<S>                                                                                 <C>               <C>
Loan with Deutsche Bank AG ("Deutsche Bank") further described below............    $ 16,189,071      $ 20,341,782
                                                                                    --------------    ---------------
Less current portion............................................................         480,567         6,750,000
                                                                                    --------------    ---------------
Total long-term debt............................................................    $ 15,708,504      $ 13,591,782
                                                                                    ==============    ===============
</Table>

     Maturities of long-term debt are as follows:

<Table>
<Caption>
YEAR                                                                                    AT DECEMBER 31,
----                                                                                    ---------------
                                                                                              2001
                                                                                              ----

<S>                                                                                          <C>
2002....................................................................                        480,567
2003....................................................................                     10,422,268
</Table>

                                       45
<Page>

<Table>
<S>                                                                                           <C>
2004....................................................................                      1,922,268
2005....................................................................                      1,922,268
2006....................................................................                      1,441,700
</Table>

     On January 25, 2000, the Company closed a credit facility with Deutsche
Bank AG, New York branch. This facility provided for Deutsche Bank to loan up to
$29,000,000 to be available in two tranches. On August 13, 2001, the Company
completed an amendment of its credit facility with Deutsche Bank. The amended
facility provides for the bank to loan up to $38,500,000 in two tranches.
Tranche A is in the amount of $30,000,000 with $13,500,000 established as the
borrowing base and $7,689,071 outstanding at December 31, 2001. Tranche A will
mature on August 13, 2002 at which time it will convert to a four year quarterly
amortizing term loan. Tranche B is in the amount of $8,500,000, of which the
entire amount was outstanding at December 31, 2001. It is payable interest only
until due on August 13, 2003, at which time the entire Tranche B balance is due.
In addition, the Company must remain in compliance with certain covenants
required by Deutsche Bank, including a re-determination 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 July 31,
2002 or the date the Tranche B Loan is repaid. The Company may repurchase this
overriding royalty interest prior to September 30, 2003, if all Tranche B loans
are repaid in full.

     As part of the credit agreement, the Company is subject to certain
covenants and restrictions, among which are limitations on additional borrowing,
and sales of significant properties, payment of dividends, working capital,
cash, and net worth maintenance requirements and a minimum debt to net worth
ratio. 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. There also is 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. The covenants regarding financial condition of the Company are as
follows:

<Table>
 <S>                                                    <C>
 Tangible Net Worth.................................    $20,000,000 plus 50% of net income from inception of the credit
                                                        agreement to the date of calculation treated as a single
                                                        period.
 Current Ratio......................................    1.0 to 1.0 (computed by including unused portion of loan
                                                        commitments in current assets and excluding current portion of
                                                        long-term debt from current liabilities).
 Debt to Capitalization.............................    0.6 to 1.0
 Interest Coverage Ratio............................    3.0 to 1.0
 Debt to EBITDA Ratio...............................    3.5 to 1.0 at any time prior to March 31, 2002, and 3.0 to 1.0
                                                        at anytime on or after March 31, 2002. (Calculation  of EBITDA
                                                        is determined  after the exclusion of all cumulative and current
                                                        effects of SFAS No. 133).
 General and Administrative Limit...................    General and  Administrative expenses shall not exceed, for any
                                                        four consecutive fiscal quarters beginning in the third quarter
                                                        of 2001, the sum of $7,000,000 plus amounts paid pursuant to the
                                                        Company's employee bonus plan, as in effect on August 13, 2001.
</Table>

     Calculation of all covenants is determined after the exclusion of all
cumulative and current effects of SFAS No. 133.

                                       46
<Page>

     As of December 31, 2001, the Company was in compliance with all above
covenants. Although the Company believes it can be in compliance with these
covenants throughout 2002 and beyond, there can be no assurance that it will
be in compliance. As a result, it is possible that waivers may be needed in
the future. In the event Deutsche Bank did not grant such waivers, if needed,
the Company would be in noncompliance of the covenants and would cause all
outstanding borrowings to become current and requiring the Company to seek
alternative financing arrangements.

     The Company has entered into an interest rate swap guaranteeing a fixed
rate of 4.5% on $10,000,000, the original Tranche B amount. The Company will
actually pay Deutsche Bank at a rate of London Interbank offered rate ("Libor")
plus 6% on Tranche B. The rate of the Tranche A loan is at Libor plus 2%. The
interest rates at December 31, 2001 for Tranche A and Tranche B were 4.46% and
8.46%, respectively. Consideration paid to the bank for the amended credit
facility included a five-year warrant to purchase 125,000 shares of the
Company's common stock for $3.00 per share. In addition, Company will pay fees
of one-half of one percent (0.5%) on the unused portion of the commitment
amount. The interest rate swap had a fair value of $408,662 at December 31, 2001
and is recorded as a current liability on the balance sheet.

6.   INCOME TAXES:

Deferred tax assets and liabilities are as follows:

<Table>
<Caption>
                                                   AT DECEMBER 31,
                                           -------------------------------
                                               2001                2000
                                           ------------       ------------
<S>                                        <C>                <C>
Net operating tax loss carryforward ....   $ 11,021,351       $ 18,176,646
Property and equipment .................     (7,014,012)         3,836,490
Valuation allowance ....................    (18,035,363)       (22,013,136)
                                           ------------       ------------
  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
carry-forwards at December 31, 2001, of approximately $31,489,573 which may
be used to offset future taxable income. The operating loss carry-forwards
will expire in the tax years 2009 through 2021.

     The ability of the Company to utilize NOL's and tax credit carry-forwards
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 carry-forwards 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.

     The tax benefit derived by applying the federal statutory tax rate to
the Company's pretax loss is offset by the valuation allowance applied to the
Company's deferred tax assets. In the fourth quarter of 2001, the Company
sold a portion of its working interest in the Runnells Field resulting in a
gain of approximately $15.6 million. After applying applicable NOL, the gain
resulted in Alternative Minimum Tax in the amount of $291,418.

7.   RELATED PARTY TRANSACTIONS:

     The President and Chief Executive Officer of the Company serves as the
President of EPC. In addition, two members of the Company's Board of
Directors serve as the President and Executive Vice President of Aspect,
respectively.

     The Company's accounts receivable balance from affiliates of the Company at
December 31, 2001 and 2000 were $360,182 and $124,268, respectively. The
accounts receivable due from Aspect at December 31, 2001

                                       47
<Page>

and 2000 were $300,161 and zero, respectively. The accounts receivable due from
EPC at December 31, 2001 and 2000 were zero and $101,199, respectively.

     The Company's accounts payable balance to the Company's affiliates at
December 31, 2001 and 2000 were zero and $269,835, respectively. The accounts
payable balance due to Aspect at December 31, 2001 and 2000 were zero and
$122,506 respectively.

8.   COMMITMENTS AND CONTINGENCIES:

     The Company leases office space under lease agreements, which are
classified as operating leases. Lease expense under these agreements was
$340,376 in 2001 and $300,290 in 2000. A summary of future minimum rentals on
these operating leases is as follows:

<Table>
<Caption>
       YEAR                                              AT DECEMBER 31,
       ----                                                    2001
                                                         ---------------
       <S>                                                  <C>
       2002............................................     $378,270
       2003............................................      291,688
       2004............................................      205,106
       2005............................................      205,106
       2006............................................      136,737
</Table>

     Minimum rentals as set forth above include $205,106 in 2004, $205,106 in
2005 and $136,737 in 2006 attributable to the lease of office space at the
Company's Houston, Texas offices. This lease can be canceled at the option of
the Company effective on or after September 1, 2004 by payment of two months
rent. In the event this option was exercised total minimum lease payments for
2004, 2005 and 2006 would be $170,922 and $0 and $0 respectively.

     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. The hedged volumes were as follows:

<Table>
<Caption>
    QUARTER ENDED                   PRICE PER MMBtu              2001 (MMBtu/DAY)             2000 (MMBtu/DAY)
    -------------                   ---------------              ----------------             ----------------
  <S>                                    <C>                           <C>                          <C>
  March 31st                             $2.45                         7,161                        9,381
  June 30th                              $2.45                         6,880                        9,031
  September 30th                         $2.45                         6,600                        8,646
  December 31st                          $2.45                         6,319                        8,278
</Table>

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 canceled. 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
were 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. Volumes
committed to the collar structure include 4,500 MMBtu per day for calendar year
2003. These hedges are accounted for as cash flow hedges pursuant to SFAS No.
133 and had a fair value at December 31, 2001 of $2,026,067.

     On January 25, 2001, the Company restructured its hedging arrangement with
Deutsche Bank and as a result, effectively settled the terms of the original
hedge. In connection with this settlement and restructuring, the Company valued
the original hedge at its fair value on the settlement date at $6,818,598. This
fair value was recognized as a charge against revenues over the term of the
original hedge through December 31, 2001. During the year ended December 31,
2001, the Company recognized in earnings $6,818,598 of losses on hedging
activities

                                       48
<Page>

related to the original hedge settled during January 2001. These losses were
partially offset by an unrealized gain on the restructured hedges of
approximately $2,980,254 during 2001.

     In the third quarter of 2000, the Company hedged an additional 5,000 MMBtu
per day of natural gas. The hedge prices as of January 1, 2001 were at $4.01 per
MMBtu for the months of January through December 2001. This hedge expired
December 31, 2001. In the fourth quarter of 2001, the Company hedged an
additional 6,500 MMBtu/day of natural gas for calendar year 2002 at a price of
$2.90 per MMBtu. This contract had a fair value at December 31, 2001 of
$302,800.

     As of January 1, 2001, the Company also had in place oil hedges for 175
barrels of oil per day in the first quarter of 2001, and 168 barrels of oil per
day, 161 barrels of oil per day and 154 barrels of oil per day for the second
through fourth quarters of 2001, respectively, all of which oil hedges were at
$21.03 per barrel. These hedges have expired and the Company currently has no
oil hedges in place. As a result, the Company has quantities of natural gas
and/or oil committed to hedge and/or collar transactions in the volumes as set
forth below:

     NATURAL GAS

<Table>
<Caption>
   QUARTER ENDED                   2001 (MMBTU/DAY)             2002 (MMBTU/DAY)             2003 (MMBTU/DAY)
   -------------                   ----------------             ----------------             ----------------
  <S>                                    <C>                          <C>                           <C>
  March 31st                             12,383                       15,000                        4,500
  June 30th                              12,900                       14,500                        4,500
  September 30th                         13,000                       14,000                        4,500
  December 31st                          13,000                       13,500                        4,500
</Table>

     OIL

<Table>
<Caption>
   QUARTER ENDED                    2001 (BBL/DAY)               2002 (BBL/DAY)               2003 (BBL/DAY)
   -------------                    --------------               --------------               --------------
  <S>                                     <C>                            <C>                          <C>
  March 31st                              175                            0                            0
  June 30th                               168                            0                            0
  September 30th                          161                            0                            0
  December 31st                           154                            0                            0
</Table>

     As a result of the above-referenced transactions, the Company has hedged
varying quantities of its natural gas through December of 2003. First quarter
2002 hedges are estimated to be approximately 95% of the Company's natural gas
production. Second quarter 2002 hedges are estimated to be approximately 85% of
the Company's natural gas production as additional wells waiting on pipeline
come on line. Future percentages will vary.

9.   PROPERTY AND EQUIPMENT:
<Table>
<Caption>
                                                                                   YEAR ENDED DECEMBER 31,
                                                                              -------------------------------
                                                                                   2001            2000
                                                                              --------------   --------------
        <S>                                                                   <C>              <C>
        Gas and oil properties, at cost, successful
             efforts method of accounting:
                 Proved...........................................            $ 38,350,379     $  29,934,906
                 Unproved, subject to amortization  ..............               1,641,900         5,334,700
                 Unproved, not subject to amortization............              55,327,431        44,689,074
                                                                              --------------   --------------
                  Total gas and oil properties....................              95,319,710       79,958,680
        Other property and equipment..............................               2,551,686        2,018,342
                                                                              --------------   --------------
        Total property and equipment..............................              97,871,396       81,977,022
        Less accumulated depletion, depreciation,
             amortization, and impairments (1)....................             (49,329,061)     (40,087,050)
</Table>

                                       49
<Page>

<Table>
<Caption>
                                                                                  YEAR ENDED DECEMBER 31,
                                                                              ----------------------------------
                                                                                   2001               2000
                                                                              ----------------    --------------
<S>                                                                           <C>                 <C>
        Total property and equipment, net.........................            $ 48,542,335        $ 41,889,972
                                                                              ================    ==============
</Table>

        (1) Includes accumulated impairments of both proved and unproved
            properties.

10.  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.

     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,
                                                                                   ------------------------------
                                                                                         2001            2000
                                                                                   --------------     -----------
<S>                                                                                <C>                <C>
Acquisition of properties:
   Proved......................................................................... $           --     $        --
   Unproved.......................................................................     11,569,664       4,525,278
Exploration costs.................................................................     23,702,948      19,491,881
Development costs.................................................................      2,932,691         916,168
                                                                                   --------------     -----------
      Total costs incurred........................................................ $   38,205,303     $24,933,327
                                                                                   ==============     ===========
</Table>

CAPITALIZED COSTS:
<Table>
<Caption>
                                                                             AT DECEMBER 31,
                                                                     -------------------------------
                                                                          2001               2000
                                                                     ------------       ------------
<S>                                                                  <C>                <C>
Proved .......................................................       $ 38,350,379       $ 29,934,906
Unproved properties, subject to amortization, net ............          1,641,900          5,334,700
Unproved properties, not subject to amortization .............         55,327,431         44,689,074
Less accumulated depletion, amortization and impairments .....         (47,736,141)       (38,806,340)
                                                                     ------------       ------------
      Net capitalized costs ..................................       $ 47,583,569       $ 41,152,340
                                                                     ------------       ------------
</Table>

                                       50
<Page>

ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:

<Table>
<Caption>
                                                                                           CRUDE OIL AND CONDENSATE
                                                                                           --------------------------
                                                                                                  (BARRELS)
                                                                                                  ---------
                                                          NATURAL GAS (MCF)
                                                          -----------------
                                                       YEARS ENDED DECEMBER 31,             YEARS ENDED DECEMBER 31,
                                                     ----------------------------          --------------------------
                                                        2001              2000               2001              2000
                                                     ----------        ----------          --------          --------
<S>                                                  <C>               <C>                 <C>                <C>
Proved developed and undeveloped reserves:
   Beginning of period .......................       21,076,278        18,793,038           454,498           372,795
   Purchases of minerals-in-place.............               --                --                --                --
   Sales of minerals-in-place ................       (6,841,711)       (3,334,327)         (250,883)          (10,653)
   Revisions of previous estimates ...........       (4,017,585)       (5,451,343)          (86,786)         (131,569)
   Extensions, discoveries and other additions       11,640,967        16,929,105           522,793           387,817
   Production ................................       (6,557,949)       (5,860,195)         (132,165)         (163,892)
                                                     ----------        ----------          --------          --------
   End of period .............................       15,300,000        21,076,278           507,457           454,498
                                                     ==========        ==========          ========          ========
Proved developed reserves:
   Beginning of period .......................       16,198,327        17,481,248           305,842           371,368
   End of period .............................       14,882,000        16,198,327           499,098           305,842
</Table>

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:

     The standardized measure of discounted future net cash flows is based on
criteria established by SFAS 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.

     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, 2001 and 2000 were as follows: 2001 - $2.31 per Mcf
of natural gas, $18.45 per barrel of oil; 2000 - $10.44 per Mcf of natural gas,
$28.73 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,
                                                                                    ------------------------------
                                                                                         2001             2000
                                                                                    -------------   --------------
<S>                                                                                 <C>             <C>
Future cash inflows..............................................................   $  44,287,840   $  233,139,437
Future development and production costs..........................................     (11,845,818)     (33,404,090)

Future income tax expenses.......................................................              --               --
                                                                                    -------------   --------------
Future net cash flows............................................................      32,442,022      199,735,347
Discount.........................................................................      (6,365,528)     (38,189,947)
                                                                                    -------------   --------------
Standardized measure of discounted future net cash flows.........................   $  26,076,494   $  161,545,400
                                                                                    =============   ==============
</Table>

                                       51
<Page>

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

<Table>
<Caption>
                                                                                      YEAR ENDED DECEMBER 31,
                                                                              ---------------------------------
                                                                                  2001                 2000
                                                                              -------------       -------------
<S>                                                                           <C>                 <C>
Standardized measure of discounted future cash flows-beginning of period      $ 161,545,400       $  32,513,100
Sales of oil and gas produced, net of operating expenses ...............        (26,293,306)        (26,505,466)
Purchases of minerals in place .........................................                 --                  --
Net changes in sales prices and production costs .......................        (99,634,878)         45,131,636
Extensions, discoveries and improved recovery, less related costs ......         19,509,442         116,249,984
Change in future development costs .....................................         (4,246,830)          3,745,484
Previously estimated development costs incurred during the year ........         (1,766,850)         (1,051,300)
Revisions of previous quantity estimates ...............................         (6,660,689)        (12,252,353)
Accretion of discount ..................................................         16,154,540           7,189,087
Net change of income taxes .............................................                 --                  --
Sales of minerals-in-place .............................................        (30,505,551)         (3,077,823)
Changes in production rates (timing) and other .........................         (2,024,783)           (396,949)
                                                                              -------------       -------------
Standardized measure of discounted future cash flows-end of period .....      $  26,076,494       $ 161,545,400
                                                                              =============       =============
</Table>

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

     Not Applicable.

                                    PART III

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

     The information required by this item is hereby incorporated by reference
to the Company's Proxy Statement, which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A. There is no additional required information.

ITEM 10. EXECUTIVE COMPENSATION

     The information required by this item is hereby incorporated by reference
to the Company's Proxy Statement which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A. There is no additional required information.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information required by this item is hereby incorporated by reference
to the Company's Proxy Statement which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A. There is no additional required information.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required by this item is hereby incorporated by reference
to the Company's Proxy Statement which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A. There is no additional required information.

                                       52
<Page>

                                     PART IV

ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K

EXHIBIT                    NAME OF EXHIBIT

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.

10(a)    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(b)    Second Amended and Restated Credit Agreement dated as of August 13,
         2001 between Esenjay Exploration, Inc. , as the Borrower, and Deutsche
         Bank AG, New York Branch, as the Lender is incorporated by reference to
         the Company's report on Form 10-QSB for the quarterly period ended June
         30, 2001 wherein same appeared as Exhibit 10.

10(c)    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.

10(d)    Agreement dated as of March 17, 2002 between Esenjay Exploration, Inc.,
         Santos Americas and Europe Corporation and ECM Acquisition Company is
         incorporated by reference to the Company's report on Form 8-K filed
         with the Securities and Exchange Commission on March 21, 2002 wherein
         same appeared as Exhibit 2.1.

11*      Statement of Earnings per Share
21*      Subsidiaries of Registrant.
(b)      Reports on Form 8-K
         Form 8-K filed on March 21, 2001 is incorporated by reference.

*Filed herewith

                                       53
<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, 2002                 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.

Date: April 16, 2002            /s/ David B. Christofferson
                                ------------------------------------------------
                                David B. Christofferson, Senior Vice President,
                                General Counsel and Chief Financial Officer

Date: April 16, 2002            /s/ Barry L. Cromeans
                                ------------------------------------------------
                                Barry  L. Cromeans, Chief Accounting Officer

Date: April 16, 2002            /s/ David W. Berry
                                ------------------------------------------------
                                David W. Berry, Chairman and Director

Date: April 16, 2002            /s/ Alex B. Campbell
                                ------------------------------------------------
                                Alex B. Campbell, Director

Date: April 16, 2002            /s/ Alex M. Cranberg
                                ------------------------------------------------
                                Alex M. Cranberg, Director

Date: April 16, 2002            /s/ William D. Dodge, III
                                ------------------------------------------------
                                William D. Dodge, III, Director

Date: April 16, 2002            /s/ Jeffrey B. Pollicoff
                                ------------------------------------------------
                                Jeffrey B. Pollicoff, Director

Date: April 16, 2002            /s/ Jack P. Randall
                                ------------------------------------------------
                                Jack P. Randall, Director

Date: April 16, 2002            /s/ Hobart A. Smith
                                ------------------------------------------------
                                Hobart A. Smith, Director

                                       54