<PAGE>

--------------------------------------------------------------------------------
                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, 1998

  [ ]            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: (512) 883-7464

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

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

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

                                  COMMON STOCK
                     SERIES B COMMON STOCK PURCHASE WARRANTS

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

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

     State issuer's revenues for its most recent fiscal year: $1,716,473

     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 $19,731,042 on March 26, 1999 (based on the last sales price of
$1.25 per share as reported on the NASDAQ Stock Market).

     15,784,834 shares as the registrant's common stock were outstanding as of
March 26, 1999.

                       DOCUMENTS INCORPORATED BY REFERENCE
Registrant's Proxy Statement for its 1998 Annual Meeting of Stockholders is
incorporated by reference into Part III.

-------------------------------------------------------------------------------
<PAGE>


                            ESENJAY EXPLORATION, INC.
                        FOR YEAR ENDED DECEMBER 31, 1998

                                TABLE OF CONTENTS
                                   FORM 10-KSB

                                     PART I

<TABLE>
<CAPTION>
Item                                                                            Page
----                                                                            ----
<S>                                                                             <C>
1.   Description of Business....................................................  3

2.   Description of Property.................................................... 20

3.   Legal Proceedings.......................................................... 22

4.   Submission of Matters to a Vote of Security Holders........................ 22

                              PART II

5.   Market for Common Equity and Related Stockholder Matters................... 23

6.   Management's Discussion and Analysis or Plan of Operation.................. 23

6A   Quantitative and Qualitative Disclosures about Market Risks................ 31

7.   Financial Statements....................................................... 32

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........................ 53

10   Executive Compensation..................................................... 53

11   Security Ownership of Certain Beneficial Owners
       and Management........................................................... 53

12   Certain Relationships and Related Transactions............................. 53

                              PART IV

13   Exhibits and Reports on Form 8-K........................................... 54

     Signatures................................................................. 56
</TABLE>

                                       2
<PAGE>

                                     PART I

         This Form 10-KSB contains forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. The Company's actual results could differ materially from
those set forth in the forward-looking statements. Certain factors that might
cause such a difference are discussed in the introductory paragraph to
Management's Discussion and Analysis beginning on page 23 of this Form 10-KSB.

ITEM 1.  DESCRIPTION OF BUSINESS
GENERAL

                                   THE COMPANY

         Esenjay Exploration, Inc. (the "Company") is an independent energy 
company engaged in the exploration for and development of natural gas and 
oil. The Company has assembled an inventory of 39 technology enhanced natural 
gas and oil exploration projects along the Texas and Louisiana Gulf Coast 
(the "Exploration Projects"). These Exploration Projects include substantial 
interests in 28 projects the Company acquired on May 14, 1998 (the 
"Acquisitions") from Esenjay Petroleum Corporation ("EPC") and Aspect 
Resources LLC ("Aspect") pursuant to an Acquisition Agreement and Plan of 
Exchange (as amended, the "Acquisition Agreement"). The Exploration Projects 
also include the Company's interests in projects acquired both before and 
after consummation of the Acquisitions. The Company, EPC and Aspect have 
spent several years identifying and evaluating many of the Exploration 
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.

         In connection with the Acquisitions, an affiliate of Enron Corp. 
exercised an option to exchange $3.8 million of debt Aspect owed to such 
Enron affiliate for 675,000 shares of the Company's Common Stock that would 
otherwise have been issued to Aspect in the Acquisitions, at an effective 
conversion rate of $5.63 per share. As a result of the Acquisitions and this 
exchange and the underwritten offering described below, EPC, Aspect and the 
Enron affiliate own approximately 32.8%, 27.7% and 4.3%, respectively, of the 
Company's outstanding Common Stock.

         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 CURRENT ACTIVITIES AND RECENT EVENTS. The Exploration
Projects encompass a relatively large number of properties which the Company
intends to drill and/or otherwise exploit on a property by property basis over a
period of time based upon various factors including terms and locations of
leases, updated current drilling results, and the overall Company exploration
strategy.

         The Company utilizes the successful efforts method of accounting. 
Under this method it expenses its dry hole costs and the field acquisition 
costs of 3-D seismic data as incurred. The undeveloped properties which were 
acquired pursuant to the Acquisitions, and which were comprised primarily of 
interests in unproven 3-D seismic based projects, 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 as periodic impairments of unproved properties 
on a straight-line basis over a period not to exceed forty-eight months, as 
well as recognizing property specific impairments. These non-cash charges 
effect all such costs which are not, in the accounting period they are to be 
impaired, supported by proven oil and gas reserves. Hence significant 
non-cash charges will likely depress reported earnings of the Company over 
the next several years, but will not effect cash flows provided by operating 
activities nor the ultimate realizable value of the Company's natural gas and 
oil properties.

         Most of the Exploration Projects have been enhanced with 3-D seismic
data in conjunction with computer aided exploration ("CAEX") technologies. The
3-D seismic data acquired to date covers approximately 1,700 square miles. A
significant number of the Exploration Projects have reached the drilling stage,
and the Company has budgeted approximately $16.5 million, in addition to funds
already spent, to fund its drilling budget in 1999. It has also budgeted
approximately $7.5 million for additional land and geophysical costs for a total
1999 capital

                                       3
<PAGE>

expenditure budget of approximately $24.0 million. The budget is projected to
fund the Company's net cost in over 40 wells. The Company does not currently
have capital resources to fund the complete 1999 budget but believes such
resources or other optional means of exploration funding will be available. (See
Management's Discussion and Analysis - Liquidity and Capital Resources). 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.

         The Company entered 1999 having gone from nominal second quarter 1998
gas and oil revenues of approximately $35,000 per month and large operating cash
flow deficits to a company with over $360,000 per month in oil and gas revenues
in the fourth quarter of 1998. This number is expected to exceed $700,000 per
month as first quarter 1999 exploration discoveries come on line and continue to
increase as additional wells are drilled. This should allow it to achieve
positive operating cash flow in 1999 and beyond. In addition, since December 31,
1998, the Company has closed a long term financing commitment for $9,000,000
with Duke Energy Field Services, Inc., it has closed a sale of project interests
to industry partners for a total of $3,768,500, and has entered into two
preliminary agreements to sell additional project interests, which it expects to
close in April 1999, for a total of approximately $3,900,000. The closed
financing, combined with the closed project sales, as well as those expected to
close, will result in an aggregate availability of over $16,600,000 in available
cash resources, which is expected to enhance working capital and contribute to
the Company's early 1999 capital expenditure plan. (See "See Management's
Discussion and Analysis - Liquidity and Capital Resources").

STRATEGY

         The Company's strategy is to expand its reserves, production and cash
flow through the implementation of an exploration program that focuses on (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 focusing on the 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 reservoir rocks high in porosity and permeability
         with profiles suitable for seismic evaluation. Unlike the Gulf of
         Mexico, where 3-D seismic data typically is owned and licensed by many
         companies that compete intensely for leases, the private right of
         ownership of onshore mineral rights enables individual exploration
         companies to proprietarily control the seismic data within focused core
         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 detect seismic anomalies in structural
         features that are not apparent in 2-D seismic surveys. The Company
         believes that 3-D seismic technology, if properly used, will reduce
         drilling risks and costs by reducing the number of dry holes,
         optimizing well locations and reducing the number of wells required to
         exploit a discovery. The Company believes that 3-D seismic surveys are
         particularly suited to its Exploration Projects along the Texas and
         Louisiana Gulf Coasts.

         EXPERIENCED TECHNOLOGICAL TEAM. The Company maintains an experienced
         technical staff, including engineers, geologists, geophysicists,
         landmen and other technical personnel. After the Acquisitions, the

                                       4
<PAGE>

         Company hired most of EPC's technical personnel, who, in some
         instances, have worked together for over 15 years. In addition, the
         Company has contracts 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 seeks to reduce exploration risks by
         primarily exploring at moderate depths that are deep enough to discover
         sizeable 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 anticipates it will identify
         potential prospects in deep gas provinces that the Company may elect to
         pursue.

         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 majority interest in many of
         the Exploration Projects, including proprietary interests in most of
         the 3-D seismic data relating to those projects. Although the Company
         has partners in the Exploration Projects in which it does not own a
         majority interest, in many cases, the Company owns a greater interest
         than any of its project partners. 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 most of the wells drilled within the
         Exploration Projects.

EXPLORATION PROJECTS

         Most of the Exploration Projects are concentrated within the Downdip
Frio, Wilcox and Texas Hackberry core project areas. The Downdip Frio core area
generally is in the middle Texas Gulf Coast where the Company believes Frio
targets exist at moderate depths. The Wilcox core area generally is in the
middle Texas Gulf Coast in an area the Company believes to have prospects for
Wilcox sand exploration. The Texas Hackberry core area is located in Jefferson
and Orange Counties, Texas, in an area which the Company believes offers
drilling opportunities in the Hackberry formations, as well as Miocene and
deeper Vicksburg sands. Other Exploration Projects consist of the Starboard
Project, as well as other 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. 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. The
Company's working interest in the wells on each Exploration Project may be
higher or lower than its Project Interest.

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

                                       5
<PAGE>

                              EXPLORATION PROJECTS

<TABLE>
<CAPTION>

                                                               ACRES LEASED OR UNDER        
                                                                 OPTION AT MARCH 26,           SQUARE MILES OF       
                                                                       1999(1)                3-D SEISMIC DATA         
                                                          ---------------------------------     RELATING TO
PROJECT AREAS                                                 GROSS                 NET         PROJECT AREA    PROJECT INTEREST(2)
                                                          ------------         ------------     ------------    ----------------
<S>                                                       <C>                  <C>              <C>             <C>

SOUTH TEXAS
DOWNDIP FRIO CORE AREA
    Allen Dome......................................            833                 136               --             50.0%
    Gillock.........................................         23,804               3,404               82             22.5%
    Blessing........................................          1,414                 278               22             24.0%
    Tidehaven.......................................          3,842               1,254               28             40.5%
    El Maton........................................          4,893               1,793               28             46.5%
    Midfield........................................          3,267               1,059               21             37.5%
    Markham.........................................          2,584               1,480               --             60.0%
    Buckeye.........................................         20,279               7,667               50             45.0%
    Duncan  Slough..................................          5,608               1,601               60             40.9%
    Southwest Pheasant..............................          3,033               1,781               10             75.0%
    Geronimo........................................          7,140               1,382               76             20.0%
    Houston Endowment...............................          3,000                 810               50             27.0%
    Wolf Point......................................            960                 437                8             45.5%
    Sheriff Field...................................          4,943               2,755               --             75.0%
    Bauer Ranch.....................................         22,000               4,803               56             33.3%
    La Rosa.........................................          5,537                 443               25             8.0%
    Piledriver......................................            640                 400                2             62.5%
    Archie .........................................            903                 207               14             25.0%
                                                           --------            --------          ------
                              Downdip Frio Sub-Total        114,680              31,690             532
WILCOX CORE AREA                                                                                               
    Gila Bend.......................................          1,179                 147               16             12.5%
    Hall Ranch......................................          7,894               3,266               57             41.5%
    Hordes Creek....................................          4,730               1,943               25             41.5%
    Mikeska.........................................          7,898               2,850               32             38.0%
    Duval/McMullen..................................          1,980               1,782               12             90.0%
    Verdad..........................................         50,994               6,930               57             25.0%
    Orangedale......................................          2,353               2,086                3             90.0%
    Riverdale.......................................          5,601               1,400               23             25.0%
                                                           --------            --------          ------
                                    Wilcox Sub-Total         82,629              20,404             225
TEXAS HACKBERRY CORE AREA
    Lox B...........................................          9,281               1,440               62             25.0%
    West Port Acres.................................            881                  86               21             12.5%
    Big Hill/Stowell................................          7,100               1,960              56              33.3%
    Lovells Lake....................................         18,213               4,262               65             33.3%
    West Beaumont...................................          1,721                  78               23             7.9%
                                                           --------            --------          ------
                           Texas Hackberry Sub-Total         37,196               7,826              227
LOUISIANA                                                                                 
    Lapeyrouse......................................          4,576                 943               35         25.0% Average
    Crab Lake.......................................          1,130                 322               12             75.0%
    S. L. Eocene(3).................................          5,516               5,416               --            100.0%
                                                           --------            --------          ------
                                 Louisiana Sub-Total         11,222               6,681              47

</TABLE>


                                         6
<PAGE>

<TABLE>
<CAPTION>

                                                               ACRES LEASED OR UNDER        
                                                                 OPTION AT MARCH 26,           SQUARE MILES OF       
                                                                       1999(1)                3-D SEISMIC DATA         
                                                          ---------------------------------     RELATING TO
PROJECT AREAS                                                 GROSS                 NET         PROJECT AREA    PROJECT INTEREST(2)
                                                          ------------         ------------     ------------    ----------------
<S>                                                       <C>                  <C>              <C>             <C>

OTHER TEXAS                                                                               
    Raymondville....................................         27,406              16,210              62              60.4%
    Caney Creek.....................................         19,759               2,334              33              12.5%
    East Texas Pinnacle Reef (4)....................             --                  --             400               --
    Papalote (3)....................................         25,316              21,685                --        87.5% Average
                                                           --------            --------          ------
                               Other Texas Sub-Total         72,481              40,229             495

MISSISSIPPI
    Thompson Creek..................................          1,877               1,562              12              93.5%
    Lipsmacker......................................          2,892                 452              64              22.0%
                                                           --------            --------          ------
                               Mississippi Sub-Total          4,769               2,014              76
                                                           --------            --------          ------
                                  TOTAL ALL PROJECTS        322,977             108,844           1,602
                                                           --------            --------          ------
                                                           --------            --------          ------
</TABLE>

-----------

(1)      Gross acres refers to the number of acres leased or under option in
         which the Company owns an undivided interest. Net acres were determined
         by multiplying the gross 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. 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. The
         Company's working interest in the wells on each Exploration Project may
         be higher or lower than its Project Interest.

(3)      Proprietary 3-D seismic data is planned to be shot over these areas in
         the near future.

(4)      Consists of 400 square miles of 3-D seismic data to which Aspect has
         rights pursuant to a license agreement, and to which the Company may
         acquire an interest pursuant to a geophysical technical services
         agreement with Aspect.

         EXPLORATION PROJECT DESCRIPTIONS. Set forth below is a description of
the Exploration Projects. The amounts specified for the interests in the
Exploration Projects and gross and net acreage of each Exploration Project and
the project description were determined as of March 26, 1999. Estimates of
drilling and completion costs are gross amounts and are not necessarily net to
the Company's interests in the related Exploration Projects. In addition,
predictions of well costs are estimates only, and actual costs may vary based
on, among other factors, down hole conditions and costs for drilling rigs at the
time of drilling. In prospects where 3-D seismic surveys are not yet shot,
processed and interpreted, such data may, when available, enhance or condemn
previously identified prospects or leads.

         DOWNDIP FRIO CORE AREA PROJECTS

         ALLEN DOME. The Allen Dome Project consists of leases and options of
approximately 833 gross acres with 271 net acres in Brazoria County, Texas. The
Company has a 50% Project Interest with 136 net acres to its interest. The
acreage targets the Frio "A" Sands and is updip from a show in the Frio "A"
Sand. Miocene potential exists in radial fault traps surrounding the dome. A
spec shoot is in the planning stage, and the Company is attempting to tie onto
the larger Speculative shoot in the area. A minimal amount of data will be
needed to image the trap. Estimated drilling and completion costs for the deep
Frio test is $1.2 million.

                                         7
<PAGE>

         GILLOCK. The Gillock Project consists of leases and options covering
approximately 23,804 gross acres with 15,129 net acres in Galveston County,
Texas, which also includes HBP leasehold. The Company has a 22.5% Project
Interest in this 3-D seismic project with 3,404 net acres to its interest. The
primary geological targets the Company has identified, for potential drilling,
are the Frio and Vicksburg Sands. A 70 square mile 3-D survey was completed in
July 1998, has been processed, and is currently being interpreted. Preliminary
interpretations have yielded several low risk prospects in the project area. The
estimated cost to drill and complete a shallow well is approximately $900,000,
with deeper wells costing over $3.5 million.

         BLESSING. The Blessing Project consists of leases and options covering
approximately 1,414 gross acres with 1,157 net acres under 22 square miles of
3-D seismic coverage in Matagorda County, Texas. The Company has a non-operated
24.0% Project Interest with 278 net acres to its interest. A 3-D seismic survey
was conducted in conjunction with the Tidehaven 3-D shoot (see "Tidehaven
Project"). The Operator has drilled two (2) Upper Frio Sand wells. One well
produced 277 MMCF per day and 4,267 BC per day in 1998, and has been recompleted
in another pay zone, which is currently producing 1400 MCF per day and 20 BC per
day; the other well was a dry hole. The Company's Working Interest in the well
is 33.935%, although the Company's Project Interest in the remaining portion of
the project is 24.0%. No wells are planned for 1999. The estimated cost of
drilling and completing a shallow well in this project area is approximately
$550,000.

         TIDEHAVEN. The Tidehaven Project consists of leases and options
covering over 3,842 gross acres with 3,097 net acres in Matagorda County, Texas.
The Company has a 40.5% Project Interest with 1,254 net acres to its interest.
These leases overlay a series of known field pays and multiple fault blocks,
which made this structure a 3-D seismic candidate. Initial interpretation of the
28 square mile 3-D seismic data set is complete. The Company has drilled and
completed two wells in the lower Frio. The first is currently producing 1.1 MMCF
per day and 7 BC per day, and the other was a dry hole. The estimated cost to
drill and complete a well ranges from approximately $550,000 to $1.5 million,
depending upon depth. There are several additional Mid Frio and Lower Frio
prospects.

         EL MATON. The El Maton Project consists of leases and options covering
approximately 4,893 gross acres with 3,856 net acres in Matagorda County, Texas.
The Company has a 46.5% Project Interest with 1,793 net acres to its interest. A
29 square mile 3-D seismic survey was started in May 1997, as an extension of
the Tidehaven shoot. This seismic survey has been completed and the
interpretation is essentially complete. The geologic setting and target zones
are the same as for Tidehaven. The Company has merged the 3-D data sets in the
El Maton, Tidehaven, Blessing, and Midfield projects. The Company has identified
several Mid Frio and Lower Frio prospect leads. The estimated cost to drill and
complete a well ranges from approximately $550,000 to $1.5 million, depending
upon depth.

         MIDFIELD. The Midfield Project consists of leases and options covering
approximately 3,267 gross acres with 2,825 net acres in Matagorda County, Texas.
The Company has a 37.5% Project Interest with 1,059 net acres to its interest.
The project is an extension of the Tidehaven, Blessing and El Maton 3-D seismic
shoots. All four of these 3-D seismic surveys have been merged. The Midfield
Project is adjacent to and up basin from, the Tidehaven Project. The geologic
setting and target zones are similar to Tidehaven. Initial data interpretation
on a 21 square mile 3-D seismic survey over this acreage is complete, and the
data has revealed two (2) low risk shallow drilling locations. The estimated
cost to drill and complete a shallow well is approximately $550,000.

         MARKHAM. The Markham Project consists of leases and options covering
approximately 2,584 gross acres with 2,466 net acres in Matagorda County, Texas.
The Company has a 60% project interest with 1,048 net acres to its interest. The
3-D has been completed, and the Company is interpreting the data. Initial review
of the seismic is encouraging and several prospects have been identified. The
estimated costs to drill and complete a shallow well is approximately $550,000,
with deeper well costing approximately $1.3 million.

         BUCKEYE RANCH. The Buckeye Ranch Project consists of approximately
20,279 gross acres with 17,037 net acres of lease options in Matagorda County,
Texas. The Company has a 45% Project Interest with 7,667 net acres to its
interest. A 3-D seismic survey has been completed, and the Company is currently
interpreting the data. The estimated cost to drill and complete a shallow well
is approximately $550,000, with deeper wells costing approximately $1.3 million.
Initial review of the seismic data is encouraging and numerous prospects have
been delineated.

                                       8
<PAGE>

         DUNCAN SLOUGH. The Duncan Slough Project consists of leases and options
covering approximately 5,608 gross acres with 3,906 net acres in Matagorda
County, Texas. The Company has a 40.99% Project Interest with 1,601 net acres to
its interest. The 3D survey has been completed, and the Company is interpreting
the data. Initial review of the seismic is encouraging and numerous prospects
have been delineated. The estimated cost to drill and complete a shallow well is
approximately $550,000, with deeper wells costing approximately $1.3 million.
The Company is planning to merge the Markham-Buckeye-Duncan Slough 3-D data with
the adjacent surveys.

         SOUTHWEST PHEASANT. The Southwest Pheasant Project consists of leases
and options covering approximately 3,033 gross acres with 2,375 net acres in
Matagorda County, Texas. The Company has a 75.0% Project Interest with 1,781 net
acres to its interest. The primary geological objectives are the middle and
lower Frio sands. A portion of the project area is covered by an old Mobil 3-D
seismic that has been reprocessed and reinterpreted. The Company has identified
several shallow prospects. The estimated cost to drill and complete a shallow
well is approximately $550,000, with deeper wells costing approximately $1.3
million.

         GERONIMO. The Geronimo Project consists of leases and options covering
approximately 7,140 gross acres with 6,911 net acres in San Patricio County,
Texas. The Company has a 20% Project Interest with 1,382 net acres to its
interest. A 76 square mile 3-D seismic survey has been shot, and the Company has
identified several prospective drillsites. One well has been drilled and is
producing 50 BO per day and 142 MCF per day. A deep Vicksburg test and an
Anderson Sand test well are currently being marketed. The estimated cost to
drill and complete a well is approximately $600,000 for a shallow well, $1.2
million for an intermediate depth well, and $4.0 million for a Vicksburg well.

         HOUSTON ENDOWMENT. The Houston Endowment Project consists of leases and
options covering approximately 3,000 gross acres with 3,000 net acres in San
Patricio and Aransas Counties, Texas. The Company has a 27.0% Project Interest
with 810 net acres to its interest. A 50 square mile 3-D seismic survey has been
acquired. Esenjay Petroleum Corporation drilled one dry hole within the project
area before execution of the Acquisition Agreement. The Company drilled an
additional Deep Frio test, which was not successful. The estimated cost to drill
and complete a shallow well is approximately $700,000 with deeper wells costing
approximately $1.3 million.

         WOLF POINT. The Wolf Point Project consists of state leases covering
approximately 960 gross acres with 960 net acres in Calhoun County, Texas. The
Company has a 45.5% Project Interest with 437 net acres to its interest. Esenjay
Petroleum Corporation drilled and completed two (2) successful wells within the
3-D seismic survey area before the Effective Date of the Acquisitions (November
1, 1997). Known field pays from this area are the 7,200-foot Frio, 7,500-foot
Frio, 7,700 foot Frio, Broughton, Oats, Upper, Middle and Lower Melbourne sands.
The Company drilled one successful well which is currently producing
approximately 1.3 MMcf per day and 13 BC per day. The Company has also drilled
one dry hole. The estimated cost to drill and complete a well is approximately
$900,000.

         SHERIFF FIELD. The Sheriff Project consists of approximately 4,943
gross acres with 3,674 net acres of lease options in Calhoun County, Texas. The
Company has a 75.0% Project Interest with 2,755 net acres to its interest. The
Company has written off most of the book value of this project and does not
expect it to play a significant part in its near term exploration activities.

         BAUER RANCH. The Bauer Ranch Project contains approximately 22,000
gross acres with 14,411 net acres of lease options in Jefferson County, Texas.
The Company has a 33.33% Project Interest with 4,803 net acres to its interest.
Numerous prospect leads have been generated within the area via log shows,
detailed structural mapping, and 2-D seismic data. Deep exploration zones also
are targeted. The Company recently completed shooting a 56 square mile 3-D
seismic survey and is currently interpreting the data. The estimated cost to
drill and complete a shallow well is approximately $650,000, with deeper wells
costing approximately $1.6 million.

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<PAGE>

         LA ROSA. The La Rosa Project consists of approximately 5,537 gross
acres with 5,537 net acres of leases and options in Refugio County, Texas. The
Company has non-operating Project Interest of between 8.0% and 13% with between
443 and 719 net acres to its interest. A 25 square mile 3-D seismic shoot has
been acquired and interpreted. Four wells have been drilled since the Effective
Date of the Acquisition for the Company's account. Three wells were dry holes.
The most recent well is currently producing 440 MCF per day. The Company has a
13% interest in this well. The estimated cost to drill and complete a Frio
formation well is approximately $450,000.

         PILEDRIVER. The Piledriver Project consists of 640 gross acres and 640
net acres of state leases located in Chambers County, Texas. The Company has a
62.5% Project Interest with 400 net acres to its interest. The objectives are
two Frio age sands. One of these target sands has what the Company believes to
be a significant gas test at the top of the sand in a well that it believes is
down dip to the Company's acreage. A 3D seismic survey was recently conducted by
Western Geophysical. The Company has acquired the data and is interpreting it at
this time before making any drilling decisions. The estimated cost to drill and
complete a well is approximately $1.85 million.

         ARCHIE. The Archie Project consists of leases covering 903 gross acres
and 826 net acres located in Chambers County, Texas. The Company owns a 25%
project interest with 207 net acres to its interest. Interpretations of the 13.4
square mile 3-D are complete and the location on the first of three low risk
prospects is being built. The target zones are the lower Frio Textularia
Mississippiensis sands. Estimated dry hole costs are $800,000.

         WILCOX CORE AREA PROJECTS

         GILA BEND. The Gila Bend Project consists of a continuous acreage block
of 1,179 gross acres with 1,179 net acres under a 16 square mile 3-D in Karnes
County, Texas. The Company has a 12.5% interest with 147 net acres to its
interest. The project is adjacent to the Company's Hall Ranch and Verdad
projects. The 3-D interpretation is complete, and a deviated well is scheduled
in the second quarter of 1999, to test multiple Wilcox Sands. The estimated cost
to drill and complete a deviated well, in the deep Wilcox, is approximately $3.0
million.

         HALL RANCH. The Hall Ranch Project consists of leases and options
covering approximately 7,894 gross acres with 7,869 net acres under a 57 square
mile 3-D seismic survey in Karnes County, Texas. The Company has a 41.5% Project
Interest with 3,266 net acres to its interest. The Company believes the Hall
Ranch area is on an under-explored ridge on trend with several producing fields.
Multiple potential pay zones in four expanded fault blocks have been delineated
in the Wilcox sands from approximately 8,000 to 17,000 feet. Known field pays
are from Wilcox reservoirs in the Migura, Roeder, Bunger, Hackney, Middle Wilcox
L series sands, and the Upper Wilcox. The Company has delineated several
potential drill sites. The Company has drilled and run production casing on its
first well on this project. The well is currently producing 5 MMcf per day
without any production decline over the last 6 months. This well was drilled at
a location in which the Company owns a 20.75% non-operated Working Interest. The
Company will own and operate 41.5% Working Interest in offset locations. The
estimated cost to drill and complete a well ranges from approximately $270,000
to $600,000 for shallow wells, while wells completed in the deep zones (to
12,500 feet) cost approximately $2.0 million.

         HORDES CREEK. The Hordes Creek Project contains leases and options on
approximately 4,730 gross acres with 4,683 net acres located in Goliad County,
Texas. The Company has a 41.5% Project Interest with 1,943 net acres to its
interest. The Company believes Hordes Creek has potential in the Miocene, Frio,
Yegua, and the Upper, Middle, and Lower Wilcox Sands. Preliminary migrated 3-D
seismic data covering 25 square miles has been interpreted. The Company has
drilled two shallow Wilcox wells in the project, both of which were dry holes. A
deep Wilcox (15,000 ft.) test is currently being marketed. A shallow Yegua well
is in the planning stage. The estimated cost to drill and complete a shallow
Yegua well is approximately $355,000.00. The estimated cost to drill and
complete a deep Wilcox test is $2.9 million.

         MIKESKA. The Mikeska Project consists of leases covering approximately
7,898 gross acres with 7,500 net acres located in Live Oak County, Texas. The
Company has a 38.0% Project Interest with 2,850 net acres to its interest.
Multiple pay potential exists from 8,500 feet to at least 16,000 feet. This
portion of the Wilcox trend contains known pays from the Hockley, four Queen
City sands, four Slick sands, six Luling sands, three Tom Lyne sands and three
to five House sands. A 32 square mile 3-D seismic survey has been shot and the
data has been 

                                       10
<PAGE>

recently reprocessed and is being reinterpreted. One well has been
drilled and completed as a low volume oil well and is not an impact well. A
second well has been completed and tested 9 MMCF per day plus water, and is
awaiting pipeline connection. The Company has identified several drill sites
updip to the discovery well. The estimated cost to drill and complete a shallow
well is approximately $800,000, with deeper wells costing approximately $1.4
million.

         DUVAL/MCMULLEN. The Duval/McMullen Project consists of approximately
1,980 gross acres with 1,980 net acres of options in Duval and McMullen
Counties, Texas. The Company has a 90.0% Project Interest with 1,782 net acres
to its interest. The Company is negotiating with Western Geophysical to acquire
a one-year-old proprietary 3-D seismic survey. The Company plans to interpret
the 3-D seismic data before drilling. The estimated cost to drill and complete a
shallow well is approximately $800,000, with deeper wells costing approximately
$1.2 million. These leases have not been available prior to the 3D seismic data
being acquired and released. Vastar Resources has recently enjoyed significant
drilling success adjacent to Esenjay's acreage.

         VERDAD. The Verdad Project consists of leases and options covering
approximately 50,994 gross acres with 27,721 net acres under a 40 square mile
3-D seismic survey in Karnes County, Texas. The Company owns a non-operated 25%
interest in this project with 6,930 net acres to its interest. Verdad has
potential pays in the shallow Frio, Yegua, and Upper Wilcox, as well as the
upside potential in the numerous Middle and Lower Wilcox reservoirs. This
project is adjacent to the Company's Hall Ranch Project. The Company expects to
begin interpreting data in mid April 1999. Estimated drilling and completed well
costs in the project area range from approximately $270,000 to $600,000 for
shallow wells, while wells completed in the deep zones cost approximately $1.8
million.

         ORANGEDALE. The Orangedale Project consists of approximately 2,353
gross acres with 2,318 net acres of leases in Bee County, Texas. The Company has
a 90% interest with 2,086 net acres to its interest. The prospect was originally
a subsurface idea backed up by 2-D data and then was recently shot as a large
spec 3-D shoot by a third party. Esenjay has rights to and has interpreted three
square miles of the 3-D data. Seitel has recently shot another 3-D survey, which
will overlap the survey shot by Edge in 1997, and will also cover additional
Esenjay leases not previously shot. Multiple pay potential exists from 8,800' to
15,000' in the expanded Upper and Middle Wilcox Sands. Wells required to test
the several proposed traps from a depth of 10,150' (non-pipe) to 15,000', cost
from $450,000 to $1,500,000, respectively.

         RIVERDALE. The Riverdale Project consists of a continuous acreage block
of 5,601 gross acres with 5,601 net acres in a complexly faulted area ten miles
west of Goliad, Texas. The Company has a 25% non-operated interest with 1,400
net acres to its interest. The Frio, Vicksburg, Hockley, Yegua, Cook Mountain
and Upper Wilcox sands from depths of 1700' to 9500' have all produced in the
immediate area and are considered to be prospective. Large untested fault blocks
have been mapped in the area using approximately 100 miles of 2-D seismic in
conjunction with the available well control. Recently Western Geophysical has
acquired 3-D data across this project and the Company is interpreting the data.
This area is adjacent to and will be merged with the Company's Hordes Creek
project. The estimated cost to drill and complete a 9500' test is approximately
$800,000.

         TEXAS HACKBERRY CORE AREA PROJECTS

         LOX B. The Lox B Project consists of 9,281 gross acres with 5,759 net
acres of leases and options in Jefferson County, Texas. The Company has a 25.0%
non-operated Project Interest with 1,440 net acres to its interest. The primary
objectives of this project are the Hackberry and Vicksburg formations. The
acreage has been evaluated with 71 square miles of 3-D seismic data. The Company
has identified numerous potential prospects through the use of seismically
detected hydrocarbon indicators. The 3-D seismic survey has been merged with the
West Port Acres data, and ultimately will be merged with the Big Hill/Stowell
and Lovells Lake 3-D seismic surveys described below. The initial well was dry
and the second well appears to be a significant discovery. The operator, H.S.
Resources, Inc. anticipates flowing the well at 15 MMCF per day and 750 BC per
day. The estimated cost to drill and complete a Hackberry well is approximately
$1.3 million, and Vicksburg wells cost approximately $1.8 million to drill and
complete.

                                       11
<PAGE>

         WEST PORT ACRES. The West Port Acres Project consists of 881 gross
acres with 686 net acres of leases in Jefferson County, Texas, which have been
acquired and a 21 square mile 3-D seismic survey has been conducted. The Company
has a 12.5% non-operated Project Interest with 86 net acres. The Company has
identified several Hackberry prospects. The estimated cost to drill and complete
a Hackberry well is approximately $1.5 million.

         BIG HILL/STOWELL. The Big Hill/Stowell Project consists of over 7,100
gross acres with 5,882 net acres of leases and options in Jefferson County,
Texas. The Company has a 33.33% Project Interest with 1,960 net acres to its
interest. The Company has entered an agreement to sell all of its undeveloped
property interests in the Big Hill/Stowell area to Helmerich & Payne, Inc.

         LOVELLS LAKE. The Lovells Lake Project consists of 18,213 gross acres
with 12,788 net acres of leases and options in Jefferson County, Texas. The
Company has a 33.33% Project Interest with 4,262 net acres to its interest. The
Company has completed a 65 square mile 3-D seismic survey, which has been
interpreted, yielding numerous Hackberry prospects. The Company has drilled and
logged 58 feet of net gas pay in the first well and is awaiting completion. A
second well is currently being drilled. The Company anticipates drilling four
additional wells in 1999. The estimated cost to drill and complete a Hackberry
well ranges from approximately $1.0 million to $1.5 million.

         WEST BEAUMONT. The West Beaumont Project consists of 1,721 gross acres
with 990 net acres of leases and options in Jefferson County, Texas. The Company
has a 7.9% non-operated Project Interest with 80 net acres to its interest. A
22.5 square mile 3-D seismic survey has been interpreted by the Company. Several
Frio and Hackberry age prospects have been identified. Two wells have been
drilled by the operator. The first well tested at 1.1 MMCF per day and 403 BO
per day. The second well has been drilled and pipe has been set awaiting
completion. The estimated cost to drill and complete a Hackberry well is
approximately $750,000. The Company has entered a contract to sell its
undeveloped property interests in this project.

         LOUISIANA PROJECTS

         LAPEYROUSE. The Company has non-operated working interests in the
leases over this project ranging from 12.0% to 46.875%, depending upon the
target formation depths. The project consists of approximately 4,576 gross and
3,772 net acres of leases in the Lapeyrouse Field in Terrebonne Parish,
Louisiana. The 3-D seismic data has been shot, processed and interpreted. After
seismic interpretation, two exploratory initial wells have been identified. Both
wells will expose the Company to significant reserve potential in a trend area
where numerous giant oil and gas fields are located. Drilling is expected to
commence in the fourth quarter of 1999. The estimated cost to drill and complete
a well is approximately $3.2 million to $5.5 million depending upon depth.

         CRAB LAKE. The Company has retained a 75% project interest, which
consists of 1,130 gross and 429 net acres of leases in Cameron Parish,
Louisiana. The primary target objectives are in the Miocene series of sands. The
Company has interpreted a 12 square mile 3-D seismic shoot, part of a 52 square
mile 3-D. The first well is scheduled to be drilled in third quarter 1999, as a
development well to extend the field. The well will test multiple objectives,
and if successful, will require further development drilling. The estimated cost
to drill and complete a well is approximately $1.1 million.

         S. L. EOCENE. The S. L. Eocene Project contains approximately 5,516
gross acres with 5,416 net acres of lease options in Beauregard Parish,
Louisiana. The Company has a 100.00% Project Interest with 5,416 net acres.
Numerous project leads have been generated within the area via log shows,
detailed facies mapping, and 2-D seismic data. The main target horizon for this
project is the Cockfield Formation. The shallower frio and deeper Wilcox zones
may also be targeted. The Company is currently marketing the project to
potential partners. The estimated cost to drill a Cockfield well is $275,000,
with a completed well cost estimated at $450,000.

         OTHER TEXAS PROJECTS

         RAYMONDVILLE. The Raymondville Project consists of approximately 27,406
gross acres with 26,849 net acres of leases and options in Willacy County,
Texas. The Company has a 60.37500% Project Interest with 16,210 net acres to its
interest. This project includes separate geologic structures known by four
different field names. The pre 3-D seismic geologic study of this area has
identified several possible drilling locations. These locations were 

                                       12
<PAGE>

selected based on subsurface well correlation and production analysis. A 62
square mile 3-D seismic survey has been acquired and currently is in processing.
The Company anticipates to begin interpreting the data in May 1999. Two of the
locations, which were identified by subsurface mapping prior to 3D seismic, have
been drilled. Both have logged multiple pay zones and both have been completed
as dual gas producers. The combined initial flow rate for the wells exceeded 10
MMcf per day, and they are currently producing 6 MMCF per day. The Company has
recently sold an 18.5% working interest for $3.76 million. The estimated cost to
drill and complete a well is approximately $550,000.

         CANEY CREEK. The Caney Creek Project consists of options and leases
covering 19,759 gross acres with 18,670 net acres in Matagorda and Wharton
Counties, Texas. The Company has a 12.5% Project Interest with 2,334 net acres
to its interest. The project targets the Frio and Yegua reservoirs. A 32 square
mile 3-D seismic survey has been conducted, and the interpretation of the data
has been completed. Several leads have been identified. The Company entered a
contract to sell its undeveloped interests in this area.

         EAST TEXAS PINNACLE REEF TREND. Aspect and certain of its affiliates
have licenses covering approximately 400 square miles of 3-D seismic data
pertaining to the East Texas Cotton Valley Reef Trend. This seismic data is
recently acquired and most of it is proprietary. Currently, there is no acreage
position or defined drilling opportunity associated with this project. The
Company intends to enter into a joint venture with Aspect or its affiliates to
attempt to generate drillable prospects. The joint venture will, if consummated,
be subject to the terms of any licensing or other agreements currently in
effect.

         PAPALOTE. The Papalote Project consists of leases and options of
approximately 25,316 gross acres with 24,783 net acres in San Patricio and Bee
Counties, Texas. The Company has ownership of between 75% and 100% in the
Project at various stages in the development of the property. A +100 square mile
3-D is planned for 1999. The project will target the Frio sands with the
Vicksburg Sands as a secondary target, and the Yegua formation as the primary
exploratory target. Several Yegua leads have been identified with subsurface and
2-D seismic. A Frio/Vicks well will cost $250,000 to drill and complete and a
Yegua well will cost approximately $1.0 million.

         MISSISSIPPI PROJECTS

         THOMPSON CREEK. The Thompson Creek Project consists of approximately
1,877 gross acres with 1,671 net acres of leases and options in Wayne County,
Mississippi. The Company has a 93.5% Project Interest with 1,562 net acres to
its interest. Approximately 12 miles of 3D have been interpreted along the salt
ridge. The Company has written off most of the book value of this project and
does not expect it to play a significant part in its near term exploration
activities.

         LIPSMACKER. The Lipsmacker Project consists of approximately 2,892
gross acres with 2,056 net acres of leases and options in Choctaw, Alabama and
Clarke Counties, Mississippi. The Company has a 22.0% Project Interest with 452
net acres to its interest. Esenjay Petroleum Corporation completed a 64 square
mile 3-D seismic survey in the fall of 1996, and while several drilling
locations were tested, the results generally were disappointing. The Company
believes there is one additional well to be drilled. The Company is currently
marketing this prospect. The estimated cost to drill and complete a well is
approximately $1.2 million.

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

                                       13
<PAGE>

calculations needed to process such data are made possible by computer programs
and advanced computer hardware.

         While large oil companies have used 3-D seismic and CAEX technologies
for approximately 20 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. The Company began using 3-D seismic and CAEX technologies in 1992
and 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 the experiences of Aspect and EPC. 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. However, the Company has not used the technology extensively enough
to arrive at any conclusion regarding the Company's ability to interpret and use
the information developed from the technology.

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. In 1994, the Company began devoting more of its energy to the
Gulf Coast region. The Company initially entered this area by evaluating the
onshore shallow Frio/Miocene Trend. Its emphasis expanded to include larger
exploration targets represented by large geological features such as those
present in the Starboard Project. 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 along the Gulf Coast of Texas, Louisiana,
Alabama and Mississippi. The focus is on natural gas exploration prospects with
a numerical concentration along the Texas Gulf Coast, many of which were
delineated by seismic hydrocarbon indicators. Additional 2-D and 3-D seismic
surveys may be required to evaluate these areas more fully, and when determined
appropriate, the Company intends to acquire acreage and drill wells as indicated
by the evaluations.

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

ACQUISITIONS AND DIVESTMENTS

         The Company has periodically acquired producing natural gas and oil
properties. In connection with each acquisition, the Company considers (i)
current and historic production levels and reserve estimates, (ii) additional
exploration and exploitation potential via technology enhancements; (iii)
capital requirements; (iv) proximity of product markets; (v) regulatory
compliance; (vi) acreage potential; and (vii) existing production transportation
capabilities. The Company also considers the historic financial operating
results and cash flow potential of each acquisition opportunity. Evaluation of
the merits of a particular acquisition is based, to the extent relevant, on all
of the above factors as well as other factors deemed relevant by the Company's
management.

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


                                       14
<PAGE>

HEDGING ACTIVITIES AND MARKETING

         The Company markets its natural gas through monthly spot sales. Because
sales made under spot sales contracts result in fluctuating revenues to the
Company depending upon the market price of gas, the Company may enter into
various hedging agreements to minimize the fluctuations and the effect of price
declines or swings. During January 1999, the Company completed performance on a
1996 swap agreement on approximately 1,040 MMBtu's per day of Mid-Continent
natural gas production for $1.566 per MMBtu for the period beginning April 1,
1996 and ending January 31, 1999.

         In October of 1998, the Company entered into two swap agreements, one
for 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.14 per
MMBtu for the period beginning November 1998 and ending in October 1999, and the
second one for 700 MMBtu's per day of its Gulf Coast natural gas production for
$2.13 per MMBtu for the period beginning November 1998 and ending in October
1999. Both of these swap agreements were supplemented in December 1998 when the
Company entered into additional swap agreements, one of which was for 4,000
MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for
the period beginning November 1999 and ending in October 2000, and the second
one was for 700 MMBtu's per day of its Gulf Coast natural gas production for
$2.07 per MMBtu for the period beginning November 1999 and ending in October
2000. As a result of the foregoing transactions, the Company has 4,700 MMBtu's
per day of its Gulf Coast natural gas production hedged through October 2000.

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

         All of the Company's oil production is now sold under market-sensitive
or spot price contracts. The Company's revenues from oil sales fluctuate
depending upon the market price of oil. No purchaser accounted for more than 10%
of the Company's total revenue in 1997 or 1998. The Company does not believe the
loss of any existing purchaser would have a material adverse effect on the
Company.

         The Company has a credit facility with Duke Energy Field Services,
Inc., which allows the lender 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.

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 are 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

                                       15
<PAGE>

obtaining coverage may impair the Company's ability to engage in its business
activities.

REGULATION

         GENERAL. The gas and oil 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 regulation 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.

         SEISMIC PERMITS. Current law in the State of Louisiana requires permits
from owners of at least an undivided 80% interest in each tract over which the
Company intends to conduct seismic surveys. As a result, the Company may not be
able to conduct seismic surveys covering its entire area of interest. Moreover,
3-D seismic surveys typically are conducted from various locations both inside
and outside the area of interest to obtain the most detailed data of the
geological features within the area. To the extent that the Company is unable to
obtain permits to access locations to conduct the seismic surveys, the data
obtained may not be as detailed as might otherwise be available.

         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 unitization or pooling
of gas and oil properties. In addition, state conservation laws establish
maximum rates of production from gas and oil wells, generally prohibiting the
venting or flaring of gas, and impose certain requirements regarding the
ratability of production. The effect of these regulations is to limit the amount
of gas and oil the Company can produce from its wells and to limit the number of
wells or the locations at which the Company can drill. Recently enacted
legislation and regulatory action in Texas and Oklahoma is intended to reduce
the total production of natural gas in those states. Although such restrictions
have not had a material impact on the Company's operations to date, the extent
of any future impact therefrom cannot be predicted.

         NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION. Federal
legislation and regulatory controls in the United States have historically
affected the price of the natural gas produced by the Company and the manner in
which such production is marketed. The transportation and sale for resale of
natural gas in interstate commerce are regulated by the Federal Energy
Regulatory Commission ("FERC") pursuant to the Natural Gas Act and the Natural
Gas Policy Act of 1978 ("NGPA"). The maximum selling prices of natural gas were
formerly established pursuant to regulation. However, on July 26, 1989, the
Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act") was enacted, which
terminated wellhead price controls on all domestic natural gas on January 1,
1993 and amended the NGPA to remove completely by January 1, 1993 price and
nonprice controls for all "first sales" of natural gas, which will include all
sales by the Company of its own production. Consequently, sales of the Company's
natural gas currently may be made at market prices, subject to applicable
contract provisions. The FERC's jurisdiction over natural gas transportation was
unaffected by the Decontrol Act.

         The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to gas buyers and sellers
on an open and nondiscriminatory basis. The FERC's efforts have 

                                       16
<PAGE>

significantly altered the marketing and transportation of natural gas.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C
(collectively, "Order No. 636"), which, among other things, require interstate
pipelines to "restructure" their services to provide transportation separate or
"unbundled" from the pipelines' sales of gas. Also, Order No. 636 requires
interstate pipelines to provide open-access transportation on a
nondiscriminatory basis that is equal for all natural gas shippers. Order No.
636 has been implemented through decisions and negotiated settlements in
individual pipeline services restructuring proceedings. In many instances, the
result of Order No. 636 and related initiatives has been to substantially reduce
or eliminate the interstate pipelines' traditional role as wholesalers of
natural gas, and has substantially increased competition and volatility in
natural gas markets. The FERC has issued final orders in virtually all Order No.
636 pipeline restructuring proceedings. In July 1996, the United States Court of
Appeals for the District of Columbia Circuit largely upheld Order No. 636 and
remanded certain issues for further explanation or clarification. Numerous
petitions for review of the individual pipeline restructuring orders are
currently pending in that court. The issues remanded for further action do not
appear to materially affect the Company. Proceedings on the remanded issues are
currently ongoing before the FERC following its issuance of Order No. 636-C in
February 1997. Although it is difficult to predict when all appeals of pipeline
restructuring orders will be completed or their impact on the Company, the
Company does not believe that it will be affected by the restructuring rule and
orders any differently than other natural gas producers and marketers with which
it competes.

         Although Order No. 636 does not regulate natural gas production
operations, the FERC has stated that Order No. 636 is intended to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. The Company does not believe, however, that it will be affected by
any action taken with respect to Order No. 636 materially differently than other
natural gas producers and marketers with which it competes.

         The FERC has recently announced its intention to reexamine certain of
its transportation-related policies, including the appropriate manner for
setting rates for new interstate pipeline construction, the manner in which
interstate pipeline shippers may release interstate pipeline capacity under
Order No. 636 for resale in the secondary market, the price that shippers can
charge for their released capacity, and the use of negotiated and market-based
rates and terms and conditions for interstate gas transmission. Several
pipelines have obtained FERC authorization to charge negotiated rates as an
alternative to traditional cost-of-service rate making methodology. In February
1997, the FERC announced a broad inquiry into issues facing the natural gas
industry to assist the FERC in establishing regulatory goals and priorities in
the post-Order No. 636 environment. In December 1997, the FERC requested
comments on the financial outlook of the natural gas pipeline industry,
including among other matters, whether the FERC's current rate making policies
are suitable in the current industry environment. In April 1998, the FERC issued
a new rule to further standardize pipeline transaction tariffs that, as the
result of newly standardized provisions regarding firm intra day transportation
nominations, could adversely affect the reliability of scheduled interruptible
transportation service on some pipelines. While any resulting FERC action would
affect the Company only indirectly, any new rules and policy statements may have
the effect of enhancing competition in natural gas markets.

         Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the operations of
the Company. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future. The regulatory burden on the oil and natural gas industry
increases the Company's cost of doing business and, consequently, affects its
profitability and cash flow. In as much as such laws and regulations are
frequently expanded, amended or reinterpreted, the Company is unable to predict
the future cost or impact of complying with such regulations.

         LOUISIANA LEGISLATION. The Louisiana legislature passed Act 404 in
1993, which permits a party transferring an oil field site to establish a
site-specific trust account for such oil field. If the site-specific trust
account is established in accordance with the requirements of the statute, the
party transferring the oil field site shall 

                                       17
<PAGE>

not thereafter be held liable by the state for any site restoration costs or
actions associated with the transferred oil field site. The parties to a
transfer may elect not to establish a site-specific trust account, however, in
the absence of such an account, the transferring party will continue to have
liability for the costs of restoration of the site. If the parties to a transfer
elect to establish a site-specific trust account pursuant to the statute, the
Louisiana Department of Natural Resources ("DNR") requires an oil field site
restoration assessment to be made at the time of the transfer or within one year
thereafter, to determine the site restoration requirements existing at the time
of transfer. Based upon the site restoration assessment, the parties to the
transfer must propose to the DNR a funding schedule for the site-specific trust
account, providing for some contribution to the account at the time of transfer
and at least quarterly payment thereafter. If the DNR approves the establishment
and funding of the site-specific trust account, the purchaser will thereafter be
the responsible party to the state, except that the failure of a transferring
party to make a good faith disclosure of all oil field site conditions existing
at the time of the transfer will render that party liable for the costs of
restoration of such undisclosed conditions in excess of the balance of the
site-specific trust fund.

         OIL SALES AND TRANSPORTATION RATES. The FERC also regulates rates and
service conditions for interstate transportation of crude oil, liquids and
condensate, which can affect the amount the Company receives from the sale of
these products. Rates for such transportation are generally subject to an
indexing system under which rates may be increased as long as they do not exceed
an index rate that is tied to inflation. Over time, this indexing system could
have the effect of increasing the cost of transporting crude oil, liquids and
condensate by pipeline. Sales of crude oil, condensate and gas liquids by the
Company are not regulated and are made at market prices. The price the Company
receives from the sale of these products is affected by the cost of transporting
the products to market.

         ENVIRONMENTAL MATTERS. The Company's oil and natural gas exploration,
development and production operations are subject to stringent federal, state
and local laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Numerous
governmental agencies, such as the U.S. Environmental Protection Agency ("EPA"),
issue regulations to implement and enforce such laws, which often require
difficult and costly compliance measures that carry substantial administrative,
civil and criminal penalties or may result in injunctive relief for failure to
comply. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentrations of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit construction or drilling
activities on certain lands lying within wilderness, wetlands, ecologically
sensitive and other protected areas, require remedial action to prevent
pollution from former operations, such as plugging abandoned wells, or closing
pits, and impose substantial liabilities for pollution resulting from the
Company's operations. In addition, these laws and regulations may restrict the
rate of oil and natural gas production below the rate that would otherwise
exist. The regulatory burden on the oil and gas industry increases the cost of
doing business and consequently affects its profitability. Changes in
environmental laws and regulations occur frequently, and any changes that result
in more stringent and costly waste handling, storage, transport, disposal or
cleanup requirements could have a material adverse effect on the Company's
operations and financial position, as well as those of the oil and gas industry
in general. While management believes that the Company is in substantial
compliance with current applicable environmental laws and regulations and the
Company has neither experienced any material adverse effect nor experts any
significant capital expenditures from compliance with these environmental
requirements, there is no assurance that this trend will continue in the future.

         The Comprehensive Environmental Response, Compensation and Liability
Act, as amended ("CERCLA"), also known as "Superfund," and comparable state laws
imposes liability without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to be responsible for
the release of a "hazardous substance" into the environment. These persons
include (i) the current owner and operator of a facility from which hazardous
substances are released, (ii) owners and operators of the facility at the time
the disposal of hazardous substances took place, (iii) generators of hazardous
substances who arranged for the disposal or treatment at or transportation to
such facility of hazardous substances and (iv) transporters of hazardous
substances to disposal or treatment facilities selected by them. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies, and it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other pollutants into the
environment. Furthermore, although petroleum, including crude oil and natural
gas, is exempt from CERCLA, at least two courts have ruled that certain wastes
associated with the 

                                       18
<PAGE>

production of crude oil may be classified as "hazardous substances" under
CERCLA, and thus such wastes may become subject to liability and regulation
under CERCLA. Regulatory programs aimed at remediation of environmental releases
could have a similar impact on the Company.

         The Resource Conservation and Recovery Act, as amended ("RCRA"),
generally does not regulate most wastes generated by the exploration and
production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil, natural gas or
geothermal energy." However, these wastes may be regulated by EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes, and waste compressor oils, may be
regulated as hazardous waste. Pipelines used to transfer oil and gas may also
generate some hazardous wastes. Although the costs of managing solid and
hazardous waste may be significant, the Company does not expect to experience
more burdensome costs than similarly situated companies involved in oil and gas
exploration and production.

         The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has used
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by the Company or on or under other locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under the Company's control.
These properties and the wastes disposed thereon may be subject to CERCLA, RCRA,
and analogous state laws. Under such laws, the Company could be required to
remove or remediate previously disposed wastes (including waste disposal of or
released by prior owners or operators), or property contamination (including
groundwater contamination by prior owners or operators), or to perform remedial
plugging or pit closure operations to prevent future contamination.

         The Federal Water Pollution Control Act of 1972 as amended ("FWPCA"),
also known as the Clean Water Act ("CWA") and analogous state laws, impose
restrictions and strict controls regarding the discharge of pollutants including
produced waters and other oil and gas wastes, into state waters or waters of the
United States. The discharge of pollutants into regulated waters is prohibited,
except in accord with the terms of a permit issued by EPA or the state. These
proscriptions also prohibit certain activity in wetlands unless authorized by a
permit issued by the U.S. Army Corps of Engineers. Sanctions for unauthorized
discharges include administrative, civil and criminal penalties, as well as
injunctive relief.

         The Oil Pollution Act of 1990, as amended ("OPA"), pertains to the
prevention of and response to spills or discharges of hazardous substances or
oil into navigable waters of the United States. Under OPA, a person owning or
operating a facility or equipment (including land drilling equipment) from which
there is a discharge or threat of a discharge of oil into or upon navigable
waters or adjoining shorelines is liable, regardless of fault, as a "responsible
party" for removal costs and damages. Federal law imposes strict, joint and
several liability on facility owners for containment and clean-up costs and
certain other damages, including natural resource damages, arising from a spill.
The OPA establishes a liability limit for onshore facilities of $350 million;
however, a party cannot take advantage of this liability limit if the spill is
caused by gross negligence or willful misconduct or resulted from a violation of
a federal safety, construction, or operating regulation. If a party fails to
report a spill or cooperate in the cleanup, the liability limits otherwise do
not apply. Federal regulations under the OPA and FWPCA also require certain
owners and operators of facilities that store or otherwise handle oil, such as
the Company, to prepare and implement spill prevention, control and
countermeasure plans and spill response plans relating to possible discharge of
oil into surface waters. The Company believes that it is in substantial
compliance with the requirements of the OPA and FWPCA and that any
non-compliance would not have a material adverse effect on the Company.

COMPETITION

         The gas and oil industry is highly competitive in all of its phases.
The Company encounters strong competition from other gas and oil companies in
all areas of its operations, including the acquisition of exploratory and
producing properties, the permitting and conducting of seismic surveys and the
marketing of gas and oil. Many of these competitors possess greater financial,
technical and other resources than the Company. Competition for the acquisition
of producing properties is affected by the amount of funds available to the
Company, information about 

                                       19
<PAGE>

producing properties available to the Company and any standards the Company
establishes from time to time for the minimum projected return on investment.
Competition also may be presented by alternative fuel sources, including heating
oil and other fossil fuels. There has been increased competition for lower risk
development opportunities and for available sources of financing. In addition,
the marketing and sale of natural gas and processed gas are competitive. Because
the primary markets for natural gas liquids are refineries, petrochemical plants
and fuel distributors, prices generally are set by or in competition with the
prices for refined products in the petrochemical, fuel and motor gasoline
markets.

FACILITIES

         The Company leases approximately 7,600 square feet of office space in
Houston, Texas, at an annual rent of $117,068. The lease expires in September
2001. The Company leases approximately 13,279 square feet of office space in
Corpus Christi, Texas. The annual rent is $135,446, and the Lease expires on
June 30, 2003. The Company currently has more office space than it needs in
Houston, and has sublet a portion of its office space.

EMPLOYEES

         The Company has eight (8) full-time employees in its Houston, Texas
office, and 31 employees in its Corpus Christi, Texas office. Their functions
include management, production, engineering, geology, geophysics, 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.

ITEM 2.  DESCRIPTION OF PROPERTY

PRINCIPAL AREAS OF OPERATIONS

         The Company owns and operates producing properties located in four
states with proved reserves located primarily in Louisiana, Oklahoma and Texas.
Daily production from both operated and non-operated wells net to the Company's
interest averaged 1,794 Mcf per day and 24 Bbls of oil per day for the year
ended December 31, 1998 and 5,526 Mcf per day and 41 Bbls of oil per day for the
quarter ended December 31, 1998. These properties have provided most of the
Company's revenues to date.

DRILLING ACTIVITY

         In 1997, the Company participated in eight wells, drilled one sidetrack
operation in an existing wellbore, which operations have resulted in two
successful completions, six dry holes, and one unsuccessful sidetrack operation
due to mechanical difficulties. These results were all prior to the Acquisitions
in May 1998, at which time the exploration functions of the Company changed
dramatically with new projects, new management and a new focus.

         Since November 1, 1997 (the effective date of the Acquisitions) through
December 31, 1998, 24 wells have been drilled for the Company's account, of
which twelve have been completed, eleven were dry holes and one was drilling. In
the first quarter of 1999, the Company participated in the drilling of six
additional wells, of which one had been completed, two are awaiting completion,
one was a dry hole and two were drilling.

PRODUCTIVE WELL SUMMARY

         The following table sets forth certain information regarding the
Company's ownership as of December 31, 1998 of productive gas and oil wells in
the areas indicated.

                                       20
<PAGE>

<TABLE>
<CAPTION>
                           Gas                    Oil
                     ---------------       -----------------
                     Gross      Net        Gross        Net
                     -----    ------       -----      ------
<S>                 <C>       <C>         <C>          <C>
  Texas ........      12       2.73          4         0.75
  Oklahoma......       3       0.01          5         0.08
  Louisiana.....       1       0.08          0         0.00
  Kansas .......       1       0.10          0         0.00
                     -----    ------       -----      ------

  Total.........      17       2.92          9         0.83
                     -----    ------       -----      ------
                     -----    ------       -----      ------
</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,
                                                               -------------------------------------
                                                                      1998                  1997
                                                               -----------------      --------------
<S>                                                            <C>                    <C>        
Net Production:
 Oil (Bbl)................................................             8,878                7,286
 Gas (Mcf)................................................           653,325(1)           121,304
 Gas equivalent (Mcfe)....................................           706,593(1)           165,020
Average sales price:
 Oil ($ per Bbl)..........................................       $     10.92              $ 20.28
 Gas ($ per Mcf)..........................................       $      1.95              $  2.06
Average production expenses and taxes ($ per Mcfe)........       $      0.52              $  2.13(2)
</TABLE>

(1)  The majority of the net production is attributable to the fourth quarter of
     1998, during which time additional exploration discoveries commenced
     production.
(2)  This computation includes $164,792 in costs associated with the fulfillment
     of contractual transportation obligations on the Company's Mobile Bay
     Properties. If this amount were not included, the average production
     expenses and taxes per Mcfe would have been $1.13.

   LEASEHOLD ACREAGE

            The following table sets forth as of December 31, 1998, the gross
and net acres of proved developed and proved undeveloped gas and oil leases
which the Company holds or has the right to acquire. It does not include
unproven acreage, which constitutes the majority of the Company's leasehold
position.

<TABLE>
<CAPTION>
                                        Proved Developed                    Proved Undeveloped
                                    -----------------------            ------------------------
 State                               Gross             Net               Gross           Net
 -----                              -------         -------            --------       ---------
<S>                                 <C>            <C>                <C>             <C>
 Arkansas ...................           0.0             0.0             6,360.0        2,544.0
 Kansas .....................         640.0            30.6                 0.0            0.0
 Louisiana ..................         225.0           225.0             9,215.0        3,910.5
 Oklahoma ...................       2,117.0            50.4            12,908.5        3,727.2
 Texas ......................       3,016.0         1,390.2             6,980.5        1,339.0
                                    -------         -------            --------       --------
            Total ...........       5,998.0         1,696.2            35,464.0       11,520.7
                                    -------         -------            --------       --------
                                    -------         -------            --------       --------
</TABLE>

                                       21
<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 an
affiliate of a major public utility a mortgage on its interest in the Starboard
Project to secure repayment of the funding provided by the affiliate and
relating to the prospect, and has granted to Bank of America NT&SA ("B of A") a
mortgage on virtually all remaining gas and oil properties to secure repayment
of its credit facility with the bank and with Duke Energy Field Services, Inc.
("Duke"). B of A serves as collateral agent for both B of A and Duke pursuant to
an intercreditor agreement between each of them and the Company.


ITEM 3.  LEGAL PROCEEDINGS

         EPC was a defendant in a lawsuit regarding injuries to a oil field
worker not employed by the Company that resulted in a judgment against EPC of
approximately $17,700,000. The judgment was settled by EPC's insurers, who
agreed to make cash payments to the plaintiff, and by EPC who agreed to
implement a mutually agreeable work safety plan in exchange for approximately
$6.0 million in punitive damages that otherwise would have been payable to the
plaintiff. The settlement was entered into and approved by the court entering an
agreed judgment on December 3, 1997. On approximately April 16, 1998, the
plaintiff filed an action against both EPC and the Company alleging, in part,
that EPC has failed and refused to implement an appropriate safety plan and
entered into negotiations with the Company to convey material assets to it
which, if consummated, would negate plaintiffs benefits to be obtained by EPC's
safety plan, thereby fraudulently inducing plaintiff to settle the judgment
against EPC. The Company believes the claims are not supported by the facts and
are without merit. The Company has in fact implemented a safety plan as part of
its business strategy which it believes equals or exceeds the one EPC agreed to
implement. It took this action as part of its business activities and not due to
any obligation it believes exists to the Plaintiff. The Company and EPC have
been advised by counsel for the plaintiff that the litigation will be dismissed
subject to agreement on a procedure for verification of the Company's ongoing
safety plan. Charles J. Smith and Michael E. Johnson, shareholders of 100% of
the common stock of EPC, have indemnified the Company in the event that any
damages were to be assessed against the Company. In the event it is not timely
dismissed, the Company and EPC will vigorously defend the claims and the Company
does not believe it will sustain any material loss.


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

         On December 3, 1998 the Company held its Annual Meeting of
Shareholders. At said meeting Mr. Hobart Smith and Mr. William D. Dodge III were
re-elected as directors with their new terms expiring at the Annual Stockholders
Meeting in 2001. The vote totals were as follows:

<TABLE>
<CAPTION>
                              Number of               Number of Shares       Number of
                              Shares Voted            Shares Voted           Shares
                              For:                    Against:               Abstained
<S>                           <C>                     <C>                    <C>
    William D. Dodge III      14,431,500              233                    19,046
    Hobart A. Smith           14,431,566              167                    29,213
</TABLE>

There was no further business submitted to the shareholders for a vote.


                                       22
<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, its Convertible Preferred Stock and its Series A
Warrants were all admitted to trading on the NASDAQ Small Cap Market under the
symbols "FNGC" for its common stock, "FNGCP" for its Convertible Preferred
Stock, and "FNGCW" for its Series A Warrants. All of the issued and outstanding
Convertible Preferred Stock was redeemed in June of 1998. The Series A Warrants
expired in November of 1998. On August 9, 1996, Frontier Natural Gas
Corporation's Series B Warrants were admitted to trading on the NASDAQ Small Cap
Market under the symbol "FNGCZ". In May of 1998 the Company reincorporated in
the State of Delaware and changed its name to Esenjay Exploration, Inc. Its
common stock trading symbol changed to "ESNJ" and its Series B Warrant symbol to
"ESNJZ". The Series B Warrants ceased to be listed on the NASDAQ Small Cap
Market in February of 1999 due to insufficient market makers and are not
currently listed on any national market.

         The Company's common stock trades on the NASDAQ Small Cap Market under
the symbol "ESNJ". The Company estimates there are approximately 95 common
shareholders of record and 2,355 beneficial owners of the common stock.

<TABLE>
<CAPTION>
                                                             Convertible                 Series A                   Series B
                                 Common                       Preferred                 Warrants(1)                 Warrants
                       --------------------------      ----------------------     ---------------------     --------------------
Quarter Ended             High            Low          High            Low        High            Low         High         Low
                          ----            ---          ----            ---        ----            ---         ----         ---
<S>                   <C>             <C>            <C>             <C>        <C>            <C>          <C>           <C>
December 31, 1998      $ 3  3/16       $ 1   1/2           --             --                                    5/32       1/32
September 30, 1998       4   3/8         1 13/16           --             --                                    7/32       1/32
June 30, 1998            6   3/8               4       10 1/2         10 1/2                                    3/16       1/16
March 31, 1998           7   1/8         4   1/8       10 7/8          7 1/8                                     1/4       1/16

December 31, 1997      $12             $ 4   1/8        8 1/2          7 1/8         3/8           1/64         7/16       3/32
September 30, 1997      12               3   3/4        9              7 1/4        3/16           1/16          3/4        1/8
June 30, 1997           14   1/4         10  1/8       10              9            5/16           3/16        15/16        1/2
March 31, 1997          21   3/8         12  3/8       10 5/8          9             1/2           5/32     1  11/16      11/16
</TABLE>

(1)  The Series A Warrants expired in November 1998. There were no 1998 trades
     recorded prior to their expiration.


ITEM 6.  MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

         The following discussion and analysis reviews Esenjay Exploration,
Inc.'s and/or its predecessor Frontier Natural Gas Corporation's operations for
the twelve month periods ended December 31, 1998 and 1997 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 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

         OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH MAY 1998. In
mid-1996, the Company refocused its activities from acquiring gas reserves
principally in the Mid-Continent region of the United States to concentrate on
exploration and related development drilling projects in Southern Louisiana and
along the Gulf Coast 

                                       23
<PAGE>

region of Alabama, Mississippi and Texas. During 1996 and 1997, the Company's
drilling activities, which were based primarily on 2-D seismic data, were
largely unsuccessful. This fact, along with an unexpected drop in production
from the Company's Mobile Bay area wells, greatly reduced the Company's cash and
capital resources.

         To address the Company's capital needs, the Board of Directors, at its
meeting on August 12, 1997, directed management to look for potential assets to
acquire in exchange for the Company's Common Stock, to identify and review
potential business consolidation opportunities, identify potential partners to
help fund the Company's proposed drilling activities, and to consider any other
avenues to strengthen the Company's capital resources and diversify its
exploration opportunities. The Board also directed management to reduce overhead
wherever prudently possible and the Company retained an investment advisor to
aid in achieving these objectives. The Company explored a series of such
transactions and the Board, after receipt of the advice of management and its
investment advisor, and receipt of due diligence reports and other materials,
unanimously agreed that a transaction with Aspect and EPC was the best option
for the Company's shareholders. This process led to the Company entering into
the Acquisition Agreement among the Company, EPC, and Aspect. This Acquisition
Agreement, and certain provisions of it, 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.

         On May 14, 1998 after a Special Meeting of Shareholders, the Company
closed the transactions provided for in the Acquisition Agreement, implemented
the Reverse Split, and completed the Reincorporation. All references in the
accompanying financial statements to the number of common shares have been
restated to reflect the foregoing. In addition, as required by the Acquisition
Agreement, the Company called for redemption, all of its issued and outstanding
cumulative convertible preferred stock and did redeem said preferred stock. 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 members of
EPC's management that joined the Company after consummation of the acquisitions
significantly enhanced the Company's management team.

         In connection with the Acquisitions, an affiliate of Enron Corp.
exercised an option to exchange $3.8 million of debt Aspect owed to such Enron
affiliate for 675,000 shares of the Company's Common Stock that would otherwise
have been issued to Aspect in the Acquisitions, at an effective conversion rate
of $5.63 per share. As a result of the Acquisitions and this exchange and the
secondary public offering effective in July of 1998, EPC, Aspect and the Enron
affiliate own approximately 32.8%, 27.7% and 4.3%, respectively, of the
Company's Common Stock.

         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 CURRENT ACTIVITIES - SINCE MAY 1998. As a result of the
above-described acquisitions, restructuring, and the underwritten offering, the
Company believes it is positioned for a period of significant exploration
activity on its technology enhanced projects. Many of the projects have 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, took several years of time and the
investment of significant capital. Management believes the acquisition of
projects at this advanced stage has not only reduced the drilling risk, but
should allow the Company to consistently drill on a broad array of exploration
prospects in 1999 and subsequent years. On Exploration Projects acquired
pursuant to the Acquisitions, the Company has participated in the drilling of
twenty-four wells through December 31, 1998 with working interests which range
from 8% to 79%. Out of the twenty-four wells drilled, twelve wells have been
completed, eleven were dry holes, and one is being drilled. Several of the
successful wells went into production late in the third quarter of 1998, and in
the fourth quarter of 1998. In addition, in the first quarter of 1999, the
Company participated in six additional wells of which one was completed, two are
awaiting completion, two were 

                                       24
<PAGE>

drilling, and one was dry. As a result, management believes net daily oil and
gas production, which currently approximates 5,300 Mcfe per day, will increase
to approximately 13,500 Mcfe per day as production from the new discoveries
comes on line.

         The Company entered 1999 having gone from nominal second quarter 1998
gas and oil revenues of approximately $35,000 per month and large operating cash
flow deficits to a company with over $360,000 per month in oil and gas revenues
in the fourth quarter of 1998. This number is expected to exceed $700,000 per
month as first quarter 1999 exploration discoveries come on line and continue to
increase as additional wells are drilled. This should allow it to achieve
positive operating cash flow in 1999 and beyond. In addition, since December 31,
1998, the Company has closed a long term financing commitment for $9,000,000
with Duke Energy Field Services, Inc., it has closed a sale of project interests
to industry partners for a total of $3,768,500, and has entered into two
agreements to sell additional project interests for a total of approximately
$3,900,000. The closed financing, combined with the closed project sales, as
well as those expected to close, will result in an aggregate availability of
over $16,600,000 in available cash resources, which is expected to enhance
working capital and contribute to the Company's early 1999 capital expenditure
plan. (See "Liquidity and Capital Resources").

         The Company will look to a variety of sources to fund its continuing
capital expenditures budget, including it's new credit facilities and sales of
promoted project interests to industry partners, as it seeks to maximize its
interests and manage its risks while aggressively pursuing its exploration
projects. (see "Liquidity and Capital Resources")

         SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes
the successful efforts method of accounting. Under this method it expenses its
dry hole costs and the field acquisition costs of 3-D seismic data as incurred.
The undeveloped properties which were acquired pursuant to the Acquisitions, and
which were comprised primarily of interests in unproven 3-D seismic based
projects, 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 as periodic
impairments of unproved properties on a straight-line basis over a period not to
exceed forty-eight months, as well as recognizing property specific impairments.
These non-cash charges effect all such costs which are not, in the accounting
period they are to be impaired, supported by proven oil and gas reserves. Hence
significant non-cash charges will likely depress reported earnings of the
Company over the next several years, but will not effect cash flows provided by
operating activities nor the ultimate realizable value of the Company's natural 
gas and oil properties.

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

YEAR 2000

         The Company is exposed to the risk that the Year 2000 issue could cause
system failures or miscalculations causing disruptions of operations, including,
among other things, a temporary inability to process transactions, send joint
interest billings, or engage in similar normal business activities. During 1998,
the Company undertook a corporate-wide initiative designed to assess the impact
of the Year 2000 issue on software and hardware utilized in the Company's
operations.

         The Company's initiative is to be conducted in these phases:
assessment, implementation and testing. During the assessment phase, the Company
completed a comprehensive inventory of all "mission critical" systems and
equipment. Many of the Company's systems include hardware and packaged software
purchased from large vendors who have represented that these systems are already
Year 2000 compliant.

         The Company relies on other producers and transmission companies to
conduct its basic operations. Should any third party with which the Company has
a material relationship fail, the impact could impair the Company's ability to
perform its basic operation. Examples of such changes are an inability to
transport production to market or an inability to continue drilling activities.
As part of the Company's assessment phase, the Company will address the most
reasonably likely worst-case scenarios and potential costs.

         The majority of the Company's technical applications are not date
sensitive. Of those applications that are 

                                       25
<PAGE>

date sensitive, most have recently been, or are currently being, upgraded. The
Company intends to complete the testing of Year 2000 modifications during the
third quarter of 1999. The Company has not established a contingency plan but
intends to formulate one to address unavoidable risks, including those discussed
above. The Company expects to have the contingency plan formulated by the third
quarter of 1999.

         The Company's efforts with respect to the Year 2000 issue have been
handled internally by management and other Company personnel. Costs of
developing and carrying out this initiative are being funded from the Company's
operations and have not represented a material expense to the Company. The
Company has not completed its assessment but currently believes that the costs
of addressing the Year 2000 issue should not be significant and should not have
a material adverse impact on the Company's financial condition.

COMPARISON OF 1998 TO 1997.

         All comparative discussions should be considered in the context of the
Acquisitions closed on May 14, 1998, which, together with related changes
significantly modified the scope, focus and the method of doing business of the
Company. As a result, the comparisons are of more limited value when analyzing
relevant trends.

REVENUE. Total revenues increased 88.9% from $908,609 for the year ended
December 31, 1997 to $1,716,473 for the year ended December 31, 1998.

         Total gas and oil revenues increased 106.6% from $664,126 to
$1,372,002. The increase in gas and oil revenue was attributed mainly to
revenues from wells placed into production during the third and fourth quarters
of 1998. There was a decrease in gain on the sale of assets of $446,445 from
$452,020 reported for 1997 to $5,375 reported for 1998. As a result of the
increase in operations stemming from both exploratory and developmental
drilling, operating fees increased 412.6% from $55,021 for 1997 to $282,020 for
1998. The Company realized a loss from various commodity transactions totaling
$113,911 for 1998 as compared to $375,410 for 1997. These losses were attributed
to various transactions in which the Company hedged its future gas delivery
obligations as a requirement of its bank loan facility. In addition to the
realized losses from commodity transactions, the Company recorded $128,936 in
unrealized gain for 1998 as compared to an unrealized loss of $128,936 for 1997.
This was due to the fact that by year end 1998 the Company's average production
volumes exceeded the hedged volumes, and it was able to fulfill its hedge
commitments. In addition to the foregoing, the Company had other revenues of
$42,051 for 1998 as compared to $241,788 for 1997.

         COSTS AND EXPENSES. Total costs and expenses of the Company increased
429.4% from $5,862,412 for 1997 compared to $31,037,820 for 1998. The increases
primarily relate to the changes in scope, focus and method of doing business
which occurred upon closing of the Acquisitions. As a result, staffing and
activity volume increased dramatically. Also foundational was the increase in
3-D seismic and other geological and geophysical work intended to lead to
increased, risk-controlled drilling and ultimately increased gas and oil
reserves and production. Increasing during the year were amortization of gas and
oil properties, exploration costs-geological and geophysical, exploration
costs-dry hole, general and administrative costs, depletion, depreciation, and
amortization, interest expense and production taxes. Partially offsetting the
foregoing increases were decreases in lease operating expenses, transportation
and gathering costs, and delay rentals.

         AMORTIZATION OF UNPROVED PROPERTIES FOR IMPAIRMENT was $6,937,300 in
1998 (none in 1997). The Company will amortize the undeveloped and unevaluated
value of the properties acquired pursuant to the Acquisitions over a period not
to exceed forty-eight months. (See "Successful Efforts Accounting and Related
Matters.")

         IMPAIRMENT OF GAS AND OIL PROPERTIES increased from $349,384 in 1997 to
$5,832,024 in 1998. This non-cash impairment in 1998 is primarily the result of
the expanded property base acquired pursuant to the Acquisitions. Management's
periodic review of each individual Exploration Project resulted 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. The impairment charges incurred were primarily attributable to
the Sheriff, Thompson Creek, and Vicksburg Phase II Exploration Projects. In
addition, $1,560,990 of impairment was taken on producing properties for which
the book value exceeded estimated future cash flow.

                                       26
<PAGE>

         EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL increased 1,110.5% from
$485,956 for 1997 to $5,882,307 for 1998. These exploration costs reflect the
costs of topographical, geological and geophysical studies and include the
expenses of geologists, geophysical crews and other costs of acquiring and
analyzing 3-D seismic data. The Company's exploration technology enhanced
exploration program on the Exploration Projects has required the acquisition and
interpretation of substantial quantities of such data and these costs have
greatly increased for 1998 as compared with 1997. 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.

         EXPLORATION COSTS - DRY HOLE increased 194.1% from $1,772,746 for 1997
to $5,213,930 for 1998 as a result of increased drilling activity in 1998.
During the year, the Company participated in the drilling of twenty-four wells
of which eleven were dry holes that were expensed.

         GENERAL AND ADMINISTRATIVE EXPENSES increased 117.4% from $2,070,812
for 1997 as compared to $4,501,656 for 1998. This was primarily attributable to
increases in operational expenses incurred after May 14, 1998, the effective
date of the Acquisition Agreement with Aspect and EPC, and costs associated with
the Acquisitions, after which time the scope of the Company's activities
increased significantly. The primary components of general and administrative
expenses were payroll and payroll taxes, which increased 125% from $936,304 in
1997 to $2,104,818 in 1998, legal, accounting and other professional services
which increased 37% from $385,384 in 1997 to $528,705 in 1998.

         DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 382.1% from
$315,880 for 1997 to $1,522,771 for 1998. The increase to DD&A was primarily
attributable to wells placed in production in the third and fourth quarters of
1998.

         INTEREST EXPENSE increased 917.6% from $60,942 for 1997 to $620,121 for
1998. The increase in interest expense was primarily attributed to a credit
facility with Duke Energy Financial Services, Inc. closed in February 1998 which
was paid off in July, 1998 and an increase in borrowings pursuant to its credit
facility with Bank of America NT & SA in October, 1998. The Company capitalized
a large portion of its interest associated with its on-going projects, of which
capitalized amounts totaled $456,901 for 1998 and $235,977 for 1997.

         PRODUCTION TAXES increased 290.8% from $24,497 for 1997 to $95,728 for
1998. The increase in production taxes was attributed to revenues of wells
placed in production during the third and fourth quarters of 1998, which
increase was partially offset by a production tax refund from the State of
Oklahoma for a production enhancement project completed in 1994.

         LEASE OPERATING EXPENSE decreased 36.6% from $427,240 for 1997 to
$270,881 for 1998. The reduction in lease operating expense relates back to
ceased operational costs for the Company's Mobile Bay wells in 1997. Lease
operating costs associated with the Mobile Bay wells for 1997 included $110,000
accrued for plugging and abandonment costs. During 1998, the Company reversed
$68,739 of the accrual associated with these wells. These factors combined with
lease operating expense increases during the third and fourth quarters of 1998
because of wells placed in production during those periods. Lease operating
costs would have increased from $317,240 in 1997 to $339,620 were the Mobile Bay
wells, which are plugged and abandoned, not included. The increases would be
attributable to increased production activities in late 1998.

         TRANSPORTATION AND GATHERING COSTS decreased 98.8% from $143,265 for
1997 to $1,719 for 1998. The decrease in transportation and gathering cost was
almost entirely attributable to the ceased production of the Mobile Bay Wells.

         DELAY RENTAL EXPENSE decreased 24.7% from $211,690 for 1997 to $159,383
for 1998. These rental payments were primarily associated with the Company's
Starboard Prospect and various other prospects. The decrease was based upon the
Company's decision to release certain leases not deemed significant after
seismic evaluation.

         NET LOSS PER COMMON SHARE decreased from a net loss of $3.07 per share
for 1997 to a net loss of $2.97 per share for 1998. There was an increase in net
loss applicable to common stockholders of $24,312,527 from 1997 as compared to
1998, but it was more than offset by the increased number of weighted average
common equivalent shares at December 31, 1998, resulting from the Acquisitions
which closed May 14, 1998, and the underwritten 

                                       27
<PAGE>

common stock offering closed July 21, 1998. Approximately 9,882,000 weighted
average common equivalent shares were outstanding at December 31, 1998 as
compared to approximately 1,646,000 at December 31, 1997.

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

         The Company's future operating results will be substantially dependent
upon the success of the Company's efforts to develop the projects acquired in
the Acquisitions, as well as its other prospects.

         While management believes that said projects represent the most
promising prospects in the Company's history, and the wells drilled on projects
acquired pursuant to the Acquisitions in 1998 substantially increased the
Company's revenues, the capital expenditures planned in 1999 will continue to
require substantial outlays of capital to explore, develop and produce. 1998
drilling results have in fact resulted in substantial revenue increases which
were evidenced in the fourth quarter. Wells drilled in the fourth quarter of
1998 and first quarter of 1999 are expected to contribute to continued rapid
increases in the Company monthly gas and oil revenues as they come on line in
the first and second quarters of 1999. However, because of the Company's
expanded 1999 drilling budget capital from sources other than cash flow from
operations will continue to be required for funding planned exploration
activities.

LIQUIDITY AND CAPITAL RESOURCES

         The Company has budgeted approximately $24,000,000 to fund its 1999
capital budget which includes the drilling and/or completion of its interest in
over 40 wells on the Exploration Projects in 1999. The Company's sources of
financing include borrowing capacity under its existing credit facilities and
other potential credit facilities, the sale of promoted interests in the
Exploration Projects to industry partners and cash provided from operations.

         The Company entered 1999 having gone from nominal second quarter 1998
gas and oil production of approximately $35,000 per month and large operating
cash flow deficits to a company which averaged over $360,000 per month in oil
and gas revenues in the fourth quarter of 1998, most of which is attributable to
wells which commenced production in September and throughout the fourth quarter
of 1998. This number is expected to continue to increase. The Company believes
it will exceed $700,000 per month as exploratory discoveries from the first
quarter of 1999 come on line. Additional drilling success in 1999 is expected to
continue the trend of rapid increases. This should allow it to achieve steadily
increasing operating cash flow throughout the year (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). In addition, since December 31, 1998, the
Company has closed long term financings for $9,000,000, closed the sale of
project interests for $3,768,500, and has entered preliminary agreements to sell
certain project interests to two industry partners for a total of approximately
$3,900,000. The resultant aggregate availability of approximately $16,600,000 in
cash is expected to enhance working capital and fund the Company's exploration
plan into the second quarter of 1999.

         The two transactions include a sale to Helmerich & Payne, Inc. ("H&P")
and a sale to Aspect Resources LLC ("Aspect"), an affiliate. The Company has
entered an agreement to sell to H&P all of its undeveloped property interests in
the Big Hill/Stowell project area and any interests in a project area called
Gill East for $1,300,000. Closing is to occur in May 1999. It has also entered
into an agreement to sell to Aspect a 12.5% (of 100%) interest in the Caney
Creek Project, a 12% (of 100%) interest in the Gillock Project, and all of the
Company's undeveloped property interests in the West Beaumont project area for
$2,610,000. Closing is scheduled for April 1999. Proceeds from the sale will be
used to settle amounts due Aspect. In that Aspect is a related party, closing is
subject to receipt of an independent fairness opinion which management believes
will be timely obtained.

         On October 23, 1998, the Company amended and restated its credit
agreement dated January 3, 1996 with B of A. The amended agreement is in a total
amount of $20,000,000 and provided for an immediate borrowing base of up to
$9,000,000. The Company had drawn $7,500,000 pursuant to the B of A loan
facility as of December 31, 1998, and March 26, 1999. The loan is in two
tranches. Tranche A is a revolving facility with no required principal payments
for two years after which it converts into a thirty-six month term loan. Tranche
B is payable in interest only until maturity in eighteen months. Both loans are
at a varied interest rate utilizing either the B of A's Alternate Reference Rate
(Alternate Reference Rate is the greater of (i) B of A's Reference Rate and (ii)
the Federal Funds 

                                       28
<PAGE>

effective rate plus 0.50%) or the London Interbank rate plus 2% for Tranche A
and 4% for Tranche B. The remaining funds will be available for future drilling
activities of the Company, subject to the approval of the bank. The Tranche A
loan is secured by a mortgage on most proven properties currently owned by the
Company. In addition, certain mortgages on the Company's exploration project
inventory secure Tranche B of the credit facility with B of A as well as the
entire credit facility with Duke discussed below. All such shared collateral is
governed by an intercreditor agreement between B of A and Duke in which B of A
serves as the collateral agent. In addition to the foregoing, B of A received a
2.0% overriding royalty interest, proportionately reduced to the Company's net
interest, in the properties classified as proven as of the date of closing and
received a five year warrant to purchase 95,000 shares of common stock at a
price equal to the average daily closing price of the Company's common stock for
the thirty days prior to closing of the credit agreement. The credit agreement
does not provide for any additional overriding interests in favor of B of A.
Proceeds of the loan primarily supplement working capital and exploration costs.

         On January 28, 1999, the Company closed a credit facility with Duke.
This facility provides for Duke to loan up to $9,000,000 to the Company for
eighteen months. The commitment reduces by $930,000 per quarter for five
quarters and reduces to zero on August 1, 2000. Principal outstanding cannot
exceed the commitment amount at any time. Duke is paid interest at a rate of
prime plus 4%. It also received a right to gather and process, at fair market
value, gas and condensate from a designated area of interest, and a net revenue
interest in certain of the Company's future drilling activities not to exceed
0.49% of the Company's net interest. Proceeds primarily supplement exploration
costs.

         On January 28, 1999, the Company, B of A, and Duke entered into an
intercreditor agreement which governs the collateral which is used to secure the
credit facility with B of A and the credit facility with Duke. Tranche A of the
B of A credit facility is secured by a first mortgage on most of the Company's
proven properties. Collateral securing amounts outstanding under both the Duke
credit facility and Tranche B of the B of A facility is primarily comprised of
mortgages taken on a significant proportion of the Exploration Projects of the
Company which have not been developed. At such time as drilling is conducted on
the Exploration Projects and proven reserves are discovered, the Company has a
right to seek increases in the available amount to be drawn under Tranche A of
its credit facility with B of A. In the event B of A agrees to increase the
amounts available pursuant to Tranche A, then, subject to Duke's consent,
security interests in proven reserves would be used as additional primary
collateral on Tranche A loans from B of A supporting the borrowing availability
increases.

         The Company will require additional sources of capital to fund its
exploration budget over the next 12 months. It anticipates substantial growth of
its credit facility with B of A as proven reserves of gas and oil are added by
its exploration program. It also plans to continue to sell promoted interests in
certain of its Exploration Projects to fund its exploration program over the
next 12 months. In the second quarter of 1999, its capital expenditures budget
will be significantly dependent upon sales of additional interests in the
Exploration Projects. Delays in such new sales would delay the drilling of
certain wells.

         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 and with cash provided by operating activities. Its
major obligations at March 26, 1999, consisted principally of (i) servicing
loans under the credit facilities with B of A and with Duke and other loans,
(ii) funding of the Company's exploration activities, and (iii) funding of the
day-to-day operating costs.

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

         In order to minimize the pricing risk associated with oil and gas
sales, the Company entered into hedging 

                                       29
<PAGE>

transactions aggregating a twenty-four month period with Bank of America's
Financial Engineering and Risk Management Group. The hedging instruments called
for the delivery of 4,700 MMBtu per day at prices which range from $2.07 to
$2.14 per MMBtu for the period November 1, 1998 through October 31, 2000.

         WORKING CAPITAL. At December 31, 1998, the Company had a cash balance
of $646,200 and a working capital deficit of $10,956,500. The working capital
deficit was primarily attributable to substantial exploratory costs, including
the substantial costs of 3-D seismic data acquisition and analysis, incurred in
1998, and deficit cash flow from operations before changes in working capital
incurred in 1998. It was also effected by the fact that the Company received
approximately $9,000,000 less in net proceeds then planned from the sale of
common stock of the Company in the third quarter. In regard to said sale, the
Company sold fewer shares for less money per share than planned in its July
underwriting primarily due to market conditions beyond its control. Gas and oil
revenues from wells which went into production in 1998 are anticipated to
generate revenues which will equal or exceed ongoing costs of operations (prior
to capital expenditures and the cost of new 3-D seismic data acquisitions) in
the first half of 1999 and beyond. Since the end of 1998, the Company has closed
the above-described credit facility with Duke, closed the sale of project
interests to Xplor Energy, Inc. for approximately $3,768,500 and entered into
two previously referenced agreements to sell additional project interests for
approximately $3,900,000, which, if all closed, will have generated to the
Company's account over $16,600,000 million in available cash resources
subsequent to December 31, 1998. Such cash resources serve to substantially
improve working capital and have served to provide significant funds for capital
expenditures.

         Due to limited working capital as described above, the Company had
slowed its exploration budget in the second half of 1998. Upon the closing of
the credit facilities with B of A, the sale of certain promoted interests and
exploration projects, and receipt of the Duke credit commitment, the Company
increased its exploration activities in the first quarter of 1999. It plans to
continue this more rapid pace of exploratory drilling activities. In order to
fully implement its 1999 exploration budget while maintaining adequate working
capital, the Company will rely upon additional sales of promoted project
interests through the summer of 1999. In this regard, it has budgeted sales to
industry partners netting approximately $10 million in net proceeds to the
Company by the summer of 1999. Delays in projected sales would delay certain
planned drilling. In the second half of the year, it projects certain increases
in its Tranche A facility with B of A. It also expects continued rapid increases
in monthly oil and gas revenues due to its exploration successes in the first
quarter of 1999. Increased revenues are anticipated to generate significantly
increasing cash flow as the year progresses, which cash flow will also further
supplement the Company's working capital.

         SUMMARY. The Company believes it is positioned for a period of
significant exploration activity on its technology enhanced projects. Many of
the projects have 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
took several years of time and the investment of significant capital. Management
believes the acquisition of projects at this advanced stage has not only reduced
the drilling risk, but should allow the Company to consistently drill on a broad
array of exploration prospects throughout 1999. As evidence of this activity the
Company has participated in the drilling of twenty-two wells from March through
December 31, 1998, with working interests which range from 8% to 79%. Out of the
twenty-two wells drilled, ten wells were completed, eleven were dry holes and
one was being drilled. In the first quarter of 1999 through March 31, 1999, the
Company participated in the drilling of six wells, of which one was completed,
two are awaiting completion, two were drilling, and one was a dry hole. The
Company's recent drilling results have served to increase its confidence in its
anticipated 1999 drilling on the technology enhanced Exploration Projects. The
Company believes its monthly oil and gas revenues will exceed $700,000 per month
(at current natural gas one year futures prices) when the recently drilled wells
are all on line late in the second quarter. In that overhead is stable,
operating cash flow should steadily and substantially increase throughout 1999.
Additional exploration success would continue this positive trend.

         In that the Company will not fund most of its 1999 capital expenditure
budget from cash flow, the Company will continue to look to a variety of sources
to fund its continuing capital expenditures budget including credit facilities
and sales of promoted project interests to industry partners, as it seeks to
maximize its interests and manage its risks while aggressively pursuing its
exploration projects. This process will be limited more by capital availability
than by its inventory of drillable prospects.

                                       30
<PAGE>

         Timing of funding its exploration budget will determine the pace of
drilling and, to the extent drilling is successful, the growth of future oil and
gas revenues. Management believes expanded credit facilities will be available
to it in 1999 if it achieves meaningful exploratory and developmental drilling
success, and that strategic sales of prospect interests will be contracted and
closed which will allow it to continue its planned exploration activities
throughout the year.

         RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In 1997, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 128, "Earnings per Share"
and SFAS No. 129, "Disclosure Information about Capital Structure," which have
been reflected in the Company's year-end 1997 and 1998 financial statements. In
1997, FASB also issued SFAS No. 130, "Reporting Comprehensive Income", SFAS No.
131, "Disclosures about Segments of an Enterprise and Related Information", and
SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities".
SFAS Nos. 130 and 131 were adopted effective January 1, 1997. The adoption of
those standards has had no impact on the Company's financial statement
presentation or disclosures as the Company had no items of other comprehensive
income and operates primarily in one segment. The Company is still evaluating
the impact of the application of SFAS No. 133, which when adopted, could have a
material effect on its financial position, liquidity or results of operations.

ITEM 6A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS.

         Market risk generally represents the risk that losses may occur in the
value of financial instruments as a result of movements in interest rates,
foreign currency exchange rates and commodity prices. The Company has entered
into interest-rate swap agreements to eliminate any movement in interest rate.

         The energy markets have historically been very volatile, and there can
be no assurance that oil and gas prices will not be subject to wide fluctuations
in the future. In an effort to reduce the pricing risks associated with oil and
gas sales, the Company entered into hedging transactions aggregating a
twenty-four month period with B of A's Financial Engineering and Risk Management
Group. The hedging instruments called for the delivery of 4,700 MMBtu per day at
prices which range from $2.07 to $2.14 per MMBtu for the period November 1, 1998
through October 31, 2000. While the use of these hedging arrangements limit the
downside risk of adverse price movements, it also limits future gains from
favorable movements to the extent of the hedged volumes.

                                       31
<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. (formerly Frontier Natural Gas Corporation) and subsidiaries
(the "Company") as of December 31, 1998 and 1997 and the related consolidated
statements of operations, stockholders' equity and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. 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, 1998 and 1997, and the results of their operations and their cash
flows for the years then ended in conformity with generally accepted accounting
principles.


Deloitte & Touche LLP
Houston, Texas

April 14, 1999

                                       32
<PAGE>


                            ESENJAY EXPLORATION, INC.
                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>

                                                                           December 31,       December 31,
                                                                              1998               1997
                                                                          ------------       -------------
<S>                                                                       <C>               <C>         
Current assets:
      Cash  and cash equivalents ....................................     $    646,200      $    690,576
      Accounts receivable, net of allowance for doubtful
           accounts of $ 348,984 at December 31, 1998
           and $ 15,488 at December 31, 1997 ........................        3,209,633           221,864
      Prepaid expenses and other ....................................          122,422           249,328
      Receivables from affiliates ...................................          963,700           105,171
                                                                          ------------       -------------
                  Total current assets ..............................        4,941,955         1,266,939
Property and equipment...............................................       70,044,882         4,404,975

Less accumulated depletion, depreciation
      and amortization ..............................................      (15,517,656)       (1,260,605)
                                                                          ------------       -------------
                                                                            54,527,226         3,144,370

Other assets ........................................................          447,091           164,699
                                                                          ------------       -------------
                  Total assets ......................................     $ 59,916,272      $  4,576,008
                                                                          ------------       -------------
                                                                          ------------       -------------

</TABLE>


                                       33

<PAGE>


                            ESENJAY EXPLORATION, INC.
                           CONSOLIDATED BALANCE SHEETS

                      LIABILITIES AND STOCKHOLDERS' EQUITY


<TABLE>
<CAPTION>

                                                                                    December 31,     December 31, 
                                                                                        1998            1997
                                                                                    ------------      ------------
<S>                                                                                 <C>             <C>         
Current liabilities:
   Accounts payable ...........................................................     $  8,993,859    $    911,396
   Accounts payable to affiliate, net .........................................        4,322,548              --
   Revenue distribution payable ...............................................        1,996,091          68,131
   Current portion of long-term debt ..........................................          101,236         401,085
   Accrued and other liabilities ..............................................          484,756         299,704
                                                                                    ------------      ------------
                  Total current liabilities ...................................       15,898,490       1,680,316


Long-term debt ................................................................        7,500,000          22,680
Non-recourse debt .............................................................          864,000         864,000
Accrued interest on non-recourse debt .........................................          331,194         194,274
                                                                                              --           9,918
Other long-term liabilities
                                                                                    ------------      ------------
                  Total liabilities ...........................................       24,593,684       2,771,188

Stockholders' equity:
   Cumulative convertible preferred stock $.01 par value;
      5,000,000 shares authorized; 85,961 shares issued and
      outstanding at December 31, 1997 ($859,610 aggregate
      redemption and liquidation preference) ..................................               --             860
   Common stock:
      Class A common stock, $.01 par value; 40,000,000
      shares authorized; 15,784,834 and 1,655,984 outstanding
      at December 31, 1998 and 1997, respectively (1) .........................          157,849          16,560
   Unamortized value of warrants issued .......................................               --         (27,163)
   Additional paid-in capital (1) .............................................       77,651,602      14,751,425
   Accumulated deficit.........................................................      (42,486,863)    (12,936,862)
                                                                                    ------------      ------------
                  Total stockholders' equity ..................................       35,322,588       1,804,820
                                                                                    ------------      ------------
                  Total liabilities and stockholders' equity...................     $ 59,916,272    $  4,576,008
                                                                                    ------------      ------------
                                                                                    ------------      ------------

</TABLE>

----------
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998, all
    numbers of shares and per share amounts have been restated for all periods
    presented.

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


                                       34

<PAGE>


                            ESENJAY EXPLORATION, INC.

                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>

                                                                 Year Ended December 31,
                                                             ------------------------------
                                                                 1998              1997
                                                             -------------     ------------
<S>                                                          <C>               <C>         
Revenues:
      Gas and oil revenues .............................     $  1,372,002      $    664,126
      Realized loss on commodity transactions ..........         (113,911)         (375,410)
      Unrealized gain (loss) on commodity transactions .          128,936          (128,936)
      Gain on sale of assets ...........................            5,375           452,020
      Operating fees ...................................          282,020            55,021
      Other revenues ...................................           42,051           241,788
                                                             ------------      ------------
                  Total revenues .......................        1,716,473           908,609
                                                             ------------      ------------

Costs and expenses:
      Lease operating expense ..........................          270,881           427,240
      Production taxes .................................           95,728            24,497
      Transportation and gathering costs ...............            1,719           143,265
      Depletion, depreciation and amortization .........        1,522,771           315,880
      Amortization of unproved properties ..............        6,937,300              --
      Impairment of oil and gas properties .............        5,832,024           349,384
      Exploration costs-geological & geophysical .......        5,882,307           485,956
      Exploration costs-dry hole .......................        5,213,930         1,772,746
      Interest expense .................................          620,121            60,942
      Delay rentals ....................................          159,383           211,690
      General and administrative .......................        4,501,656         2,070,812
                                                             ------------      ------------
                  Total costs and expenses .............       31,037,820         5,862,412
                                                             ------------      ------------
Loss before provision for income taxes .................      (29,321,347)       (4,953,803)
Benefit (provision) for income taxes ...................             --                --
Net loss ...............................................      (29,321,347)       (4,953,803)
Cumulative preferred stock dividend ....................           48,136           103,153
                                                             ------------      ------------
Net loss applicable to common stockholders .............     $(29,369,483)     $ (5,056,956)
                                                             ------------      ------------
                                                             ------------      ------------

Net loss per common share (1) ..........................     $      (2.97)     $      (3.07)
                                                             ------------      ------------
                                                             ------------      ------------

Weighted average number of common shares outstanding (1)        9,882,227         1,646,311
                                                             ------------      ------------
                                                             ------------      ------------

</TABLE>

----------
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998, all
    numbers of shares and per share amounts have been restated for all periods
    presented.

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


                                       35

<PAGE>


                            ESENJAY EXPLORATION, INC.

                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

<TABLE>
<CAPTION>


                                    Preferred                    Class A           Unamortized
                                      Stock                   Common Shares          Value of      Additional
                               -------------------       -----------------------     Warrants       Paid-in          Accumulated
                                Shares      Amount       Shares(1)     Amount(1)      Issued       Capital(1)          Deficit   
                               --------    -------       ---------     ---------   -----------    -----------       -------------
<S>                           <C>         <C>           <C>           <C>           <C>          <C>               <C>          
Balance,
 December 31, 1996.....        85,961      $ 860         1,644,317     $ 16,443      $(54,325)    $14,681,542       $ (7,905,694)

Issuance of common
   stock ..............            --         --            11,667          117            --          69,883                 --
Cumulative
   preferred stock
   dividend ...........            --         --                --           --            --              --            (77,365)
Amortization of
   warrants ...........            --         --                --           --        27,162              --                 --
Net loss ..............            --         --                --           --            --              --         (4,953,803)
                              --------     ------       ----------     ---------     ---------    ------------      -------------

Balance,
   December 31, 1997...        85,961        860         1,655,984      16,560        (27,163)     14,751,425        (12,936,862)

Issuance of common
   stock for
   Acquisitions, net...            --         --        10,106,700      101,067            --      49,360,831                 --
Redemption of
   preferred stock ....       (85,961)      (860)               --           --            --        (858,750)          (228,654)
Amortization of
 warrants .............            --         --                --           --        27,163              --                 --

Secondary common
   stock offering, net                                   4,000,000       40,000                    14,364,980                 --
Issuance of common
    stock .............                                     22,150          222                        33,116                 --
Net loss
                              --------     ------       ----------     ---------     ---------    ------------      -------------
Balance,
   December 31, 1998...            --      $  --        15,784,834     $157,849      $     --     $77,651,602       $(42,486,863)
                              --------     ------       ----------     ---------     ---------    ------------      -------------
                              --------     ------       ----------     ---------     ---------    ------------      -------------

</TABLE>


----------
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998, all
    numbers of shares and per share amounts have been restated for all periods
    presented.

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


                                       36

<PAGE>


                            ESENJAY EXPLORATION, INC.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>

                                                                                   Year Ended December 31,
                                                                               -------------------------------
                                                                                    1998              1997
                                                                               -------------     -------------
<S>                                                                            <C>               <C>          
Cash flows from operating activities:
      Net loss ...........................................................     $(29,321,347)     $ (4,953,803)
      Adjustments  to reconcile net loss to net cash provided by (used in)
         operating activities:
              Depletion, depreciation and amortization ...................        1,522,771           315,880
              Amortization of unproven property ..........................        6,937,300                --
              Impairment of oil and gas properties .......................        5,832,024           349,384
              Exploration costs ..........................................       11,096,237         2,258,702
              Gain on sale of assets .....................................           (5,375)         (452,020)
              Gain on settlement of deferred compensation agreement ......               --           (25,794)
              Amortization of financing costs and warrants ...............          136,677            46,128
              Unrealized (gain) loss on commodity transitions ............         (128,936)          128,936
      Changes in operating assets and liabilities:
              Trade and affiliate receivables ............................       (3,846,298)          191,882
              Prepaid expenses ...........................................          126,906           198,418
              Other assets ...............................................         (372,941)          272,679
              Trade and affiliate payables ...............................       11,405,011           186,174
              Revenue distribution payable ...............................        1,927,960          (292,032)
              Accrued and other ..........................................          440,990          (118,936)
                                                                               ------------      ------------
              Net cash provided by (used in) operating activities ........        5,750,979        (1,894,402)
                                                                               ------------      ------------

Cash flows from investing activities:
      Capital expenditures - gas and oil properties ......................      (29,818,845)       (3,023,253)
      Capital expenditures - other property and equipment ................         (300,724)         (159,679)
      Proceeds from sale of assets .......................................        5,191,847         1,002,540
                                                                               ------------      ------------
           Net cash used in investing activities .........................      (24,927,722)       (2,180,392)
                                                                               ------------      ------------

Cash flows from financing activities:
      Proceeds from issuance of debt .....................................       15,800,000           182,382
      Repayments of long-term debt .......................................       (8,641,494)         (296,303)
      Preferred stock redeemed ...........................................         (859,610)             --
      Preferred stock dividends paid .....................................         (228,654)          (77,365)
      Net proceeds from issuance of common stock .........................       14,438,318              --
      Cost of issuing stock ..............................................       (1,376,193)             --
                                                                               ------------      ------------
           Net cash provided by (used in) financing activities ...........       19,132,367          (191,286)
                                                                               ------------      ------------

      Net decrease in cash and cash equivalents ..........................          (44,376)       (4,266,080)

Cash and cash equivalents at beginning of year ...........................          690,576         4,956,656
                                                                               ------------      ------------

Cash and cash equivalents at end of year .................................     $    646,200      $    690,576
                                                                               ------------      ------------
                                                                               ------------      ------------

Supplemental disclosure of cash flow information:
Cash paid for interest ...................................................     $    835,186      $    141,356

</TABLE>

                                       37

<PAGE>


<TABLE>
<S>                                                                            <C>               <C>          
Supplemental disclosure of non-cash investing and financing activities:
           Acquisition of oil and gas properties .........................     $ 54,218,750              --
           Assumption of exploration and other costs .....................        2,380,659              --
           Assumption of related liabilities .............................        1,000,000              --
           Issuance of 10,106,722 shares of common stock .................       50,838,091              --

</TABLE>


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


                                       38

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

         Certain amounts from previous years have been reclassified to conform
to current presentation.

         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. 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 incurred and depleted by the unit of production method based upon estimated
proved reserves. Valuation allowances are provided if the net capitalized costs
of gas and oil properties at the field level exceed their realizable values
based on expected future cash flows. This analysis resulted in $1,560,990 of
impairment charges during 1998. Unproved properties are periodically assessed
for impairment and, if necessary, a loss is recognized. Impairments of
$4,271,034 and $349,384 were recognized in 1998 and 1997, respectively.

         In addition, the $54,200,000 fair market value assigned to unproven gas
and oil exploration projects contributed by Esenjay Petroleum Corporation
("EPC") and Aspect Resources LLC ("Aspect") pursuant to certain acquisitions of
undeveloped exploration projects (the "Acquisitions") which closed on May 14,
1998 is, until such time as the book value of each such project is either
drilled and transferred to producing properties or is otherwise evaluated as
impaired, are being amortized on a straight-line basis over a period not to
exceed forty-eight months. For the year ended December 31, 1998, such
amortization was $6,937,300.

         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.

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

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

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


                                       39

<PAGE>


         COMMODITY TRANSACTIONS - The Company attempts to minimize the price
risk of a portion of its future oil and gas production with commodity futures
contracts. Gains and losses on these contracts are recognized in the period in
which revenue from the related gas and oil production is recorded or when the
contracts are closed. To the extent that the quantities hedged under the
commodity transaction exceed current production, the Company recognizes gains or
losses on the overhedged amount.

         CAPITALIZED INTEREST - The Company capitalizes interest costs incurred
on exploration projects. Interest capitalized for the years ended December 31,
1998 and 1997 was approximately $456,901 and $235,977, 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, 1998 and 1997 was approximately 31,298 MCF
and 29,244 MCF overproduced, respectively.

         EXPLORATION COSTS - The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. In 1998
and 1997, the Company expensed $5,882,307 and $485,956 in geological and
geophysical costs respectively and $5,213,930 and $1,772,746 in dry hole costs
respectively.

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

         The Company has interest rate and gas swap agreements that subject it
to off-balance sheet risk. The unrealized losses on these contracts, as
disclosed in the following footnotes, are based on market quotes. These
unrealized losses are not recorded in the consolidated financial statements to
the extent the swaps qualify for hedge accounting.

         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, 1998 and 1997 all potentially diluted securities are anti-dilutive
and therefore are not included in the earnings per share calculation.

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

<TABLE>
<CAPTION>

                                                                                          1998               1997
                                                                                          ----               ----
<S>                                                                                       <C>               <C>      
BASIC AND DILUTED EARNINGS PER SHARE
    Weighted average common shares outstanding ...................................        9,882,227         1,646,311
    Basic and diluted loss per share .............................................     $      (2.97)     $      (3.07)
EARNINGS FOR BASIC AND DILUTED COMPUTATION
    Net loss .....................................................................     $(29,321,347)     $ (4,953,803)
    Preferred share dividends ....................................................          (48,136)         (103,153)
                                                                                       -------------     -------------
    Net loss to common shareholders (basic and diluted loss per share computation)     $(29,369,483)     $ (5,056,956)
                                                                                       -------------     -------------
                                                                                       -------------     -------------

</TABLE>


                                       40

<PAGE>


2.       RECENT EVENTS

         On January 28, 1999, the Company closed a credit facility with Duke
Energy Financial Services, Inc. ("Duke"). This facility provides for Duke to
loan up to $9,000,000 to the Company for eighteen months. The commitment reduces
by $930,000 per quarter for five quarters and reduces to zero on August 1, 2000.
Principal outstanding cannot exceed the commitment amount at any time. Duke is
paid interest at a rate of prime plus 4%. Duke also received a right to gather
and process, at fair market value, gas and condensate from a designated area of
interest, and a net revenue interest in certain of the Company's future drilling
activities not to exceed 0.49% of the Company's net interest. Proceeds from the
credit facility will primarily supplement exploration costs.

         On January 28, 1999, the Company, Bank of America NT&SA ("B of A"), 
and Duke entered into an intercreditor agreement which governs the collateral 
which is used to secure the credit facility with B of A and the credit 
facility with Duke. Tranche A of the B of A credit facility is secured by a 
first mortgage on most of the Company's proven properties at a given point in 
time. Collateral securing amounts outstanding under both the Duke credit 
facility and Tranche B of the B of A facility is primarily comprised of 
mortgages taken on a significant proportion of the exploration projects of 
the Company which have not been developed. At such time as drilling is 
conducted on the exploration projects and proven reserves are discovered, the 
Company has a right to seek increases in the available amount to be drawn 
under Tranche A of its credit facility with B of A. In the event B of A 
agrees to increase the amounts available pursuant to Tranche A, then, subject 
to Duke's consent, security interests in proven reserves would be used as 
additional primary collateral on Tranche A loans from B of A supporting the 
borrowing availability increases.

         In January 13, 1999, the Company closed the sale of approximately
23.45% of its interest in its Willacy County Project to a third party for
$3,768,500 plus potential future additional payments based upon future drilling
activity.

         On March 22, 1999, the Company entered into an agreement with Aspect to
sell a 12.5% (of 100%) interest in the Caney Creek Project, a 12% (of 100%)
interest in the Gillock Project, and all of the Company's undeveloped property
interests in the West Beaumont project area for $2,610,000. Closing is scheduled
for April 1999. In that Aspect is a related party, closing is subject to receipt
of an independent fairness opinion which management believes will be timely
obtained. Proceeds will be utilized to reduce net accounts payable of $4,322,548
at December 31, 1998 from the Company to Aspect. In addition, on March 31, 1999
the Company entered into an agreement with Helmerich & Payne, Inc. to sell all
of its undeveloped property interests in the Big Hill/Stowell project area and
an area called East Gill for $1,300,000. Closing is expected in April 1999.

3.       STOCKHOLDERS' EQUITY:

         As a result of the Company's 1:6 reverse stock split effected May 14,
1998, all numbers of common shares and per share amounts have been restated for
all periods.

         At December 31, 1996, the Company had 1,644,317 outstanding shares of
$0.01 par value common stock and 85,961 shares of cumulative convertible
preferred stock. In 1998 and 1997 the Company issued 14,128,850 and 11,667
additional shares of common stock, respectively.

         On May 14, 1998, the shareholders approved the January 19, 1998
Acquisition Agreement with EPC and Aspect. This agreement called for the Company
to issue up to 5,165,260 shares of Common Stock, after giving effect to the
reverse split, to EPC in exchange for undeveloped oil and gas prospects and to
issue up to 4,941,440 shares of Common Stock, after giving effect to the reverse
split, to Aspect in exchange for undeveloped oil and gas prospects. The combined
assets of Aspect and EPC had a historical full cost basis of $19,900,000 and a
fair value of $54,200,000 as determined by an independent assessment by
Cornerstone Ventures L.P.. In addition, after November 1, 1997 (the effective
date) and prior to the date of closing, EPC incurred approximately $3,800,000 in
exploration and development costs and $300,000 in overhead costs associated with
the prospects and Aspect incurred approximately $3,955,000 in such costs, all of
which incurred costs were for the account of the Company.

         CUMULATIVE CONVERTIBLE PREFERRED STOCK - During 1998 and 1997, $48,136
and $77,365 was declared and paid in cumulative preferred stock dividends. In
addition, during 1998 the Company paid dividends in arrears of


                                       41

<PAGE>


$180,518 ($1.50 per share) on its cumulative preferred stock for the period from
May 1, 1995 to December 31, 1998. All shares of the cumulative convertible
preferred stock were redeemed in May of 1998.

         WARRANTS - As of December 31, 1996, there were 263,013 Series A
Warrants outstanding. All of the Series A Warrants expired on November 13, 1998.

         Since December 31, 1996, the Company has had Series B Warrants, which
entitles the holder to purchase one-sixth (1/6) share of common stock for $12.15
commencing August 8, 1997, and ending August 8, 2001. Each Series B Warrant is
redeemable by the Company with the prior consent of the underwriter at a price
of $0.06 per Series B Warrant, at any time after the Series B Warrants become
exercisable, upon not less than 30 days notice, if the last sale price of the
common stock has been at least 200% of the then exercise price of the Series B
Warrants for the 20 consecutive trading days ending on the third day prior to
the date on which the notice of redemption is given.

         The Company had also issued a common stock warrant to purchase 4,167
shares of common stock at $24.00 per share in connection with a loan agreement.
This warrant expired on November 13, 1998. The loan was paid in full in 1993.

         The Company and Hi-Chicago Trust agreed to a settlement in December
1995 whereby the Company issued 12,500 shares of common stock and a stock
purchase warrant to purchase up to 50,000 shares of common stock at an exercise
price of $18.00 per share to settle a claim asserted by Hi-Chicago Trust. The
warrant is exercisable through the earlier of 60 months from the settlement date
or for a period of 30 days after the closing bid price of the Company's stock
equals or exceeds $36.00 per share for sixty consecutive trading days. The
issued shares are unregistered.

         In 1996, the Company issued to a bank providing financing, a warrant to
purchase up to 41,667 shares of common stock for a period of five years
beginning January 3, 1996, at an exercise price of the highest average of the
daily closing bid prices for thirty (30) consecutive trading days between
January 1, 1996, and June 30, 1996. The Company has recorded the warrants at a
value of approximately $82,500 as unamortized value of warrants issued. The
warrants were amortized using the interest method and were fully amortized
during 1998.

         The Company has also issued a warrant to purchase 41,667 shares of the
Company's common stock at $12.00 per share to a financial advisor. The warrant
has a five year term commencing on January 12, 1996 and provides for anti-
dilution protection, registration rights, and permits partial exercise at the
election of the holder by exchanging the warrants with appreciated value equal
to each exercise price in lieu of cash. The Company has recorded the warrants at
their fair value of approximately $33,000.

         On January 15, 1997, the Board of Directors authorized the Company to
enter into an agreement with a company to perform investor relations services
for the Company on a fee basis through January 15, 1999, and month to month
thereafter, which fee may be paid either in cash or common stock at the election
of the Company. The Company elected to compensate the investor relations firm
partially in cash and partially in stock, therefore the investor relations firm
was issued 11,667 shares of common stock during 1997 and 12,500 shares in 1998.

         In the first quarter of 1998, the Company, in connection with a
financing arrangement, issued warrants to purchase 25,000 shares of common stock
at an exercise price of $3.00 per share.

         On October 13, 1998, the Company entered into an amended credit
agreement with B of A part of which called for the Company to issue warrants to
purchase 95,000 shares of common stock at a price per share equal to the average
daily closing price of the Company's common stock during the 30 calendar days
prior to closing. The warrants have a five year term and provide for usual and
customary anti-dilution protection, registration rights, and put and call
provisions (including a call on the warrants if the stock price exceeds five
times the strike price).

         EMPLOYEE OPTION PLAN-1997 - The plan authorizes the issuance of up to
115,892 options to purchase one share of common stock. Options to purchase
94,001 shares of common stock at prices ranging from $3.78 to $7.68 are
currently outstanding.


                                       42

<PAGE>


         Under the plan, 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; such is the 
case of certain officers reissued options under this plan during 1997. Unless 
otherwise so designated, the options shall be exercisable at a rate of 33 
1/3% on January 1, the year following the effective date of the grant, and 33 
1/3% each January 1 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.

         MANAGEMENT INCENTIVE STOCK PLAN - The Plan initially authorized the
issuance of up to 40,000 units. Each unit consisted of (i) an option to purchase
one share of Common Stock and (ii) a cash payment ("Stock Appreciation Right" or
"SAR") to be made by the Company when the option is exercised. The value of the
SAR was equal to twice the amount by which the fair market value of the Common
Stock on the date of the exercise of the option exceeds the exercise price.
Currently all units have expired or have been canceled by the Board of Directors
and the plan is not effective.

         The following table summarizes activity under the Company's stock
option plans for the years ended December 31, 1998 and 1997.

<TABLE>
<CAPTION>

                                                  Incentive              Management         Stock Incentive      Employee Option
                                              Stock Option Plan     Incentive Stock Plan    Option Plan 1997         Plan 1997
                                              -----------------     --------------------    ----------------     ---------------
                                                 1998    1997        1998        1997       1998       1997       1998       1997
                                                 -----   -----       -----       ----       ----       ----       ----       -----
<S>                                            <C>       <C>         <C>       <C>         <C>      <C>         <C>        <C>
Shares available for grant............            --        --        --            --        --      1,333      115,892    115,892
Shares under option at end of period..
                                                  --        --        --         8,000        --     20,333       94,001    100,167
                                                                               $ 12.00-    $8.82-   $  3.78-    $   3.78-    
Option price per share................            --        --        --         21.00        --      12.75         7.68      11.28
Shares exercisable at end of period...
                                                  --        --        --         8,000        --      6,778       90,667     90,667
Sales canceled........................            --    30,000        --        10,667        --     36,667           --         --
Weighted option price.................            --        --        --       $ 18.12        --    $ 10.02     $   3.92   $   4.20
Weighted average fair value
    of options granted during
    the year at market price.........                                                                                 --   $   3.30

</TABLE>


         STOCK OPTION PLANS - The Company has one active fixed option plan which
reserves shares of common stock for issuance to executives, key employees and
directors. The Company has adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation". Accordingly, no compensation cost has been recognized for the
stock option plans. Had compensation cost for the Company's stock option plans
been determined based on fair value at the grant date for awards in 1998 and
1997 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>

                                                                     1998               1997
                                                                     ----               ----
<S>                                                               <C>               <C>         
Net loss applicable to common stockholders-as reported.......     $(29,369,483)     $(5,056,956)

Net loss applicable to common stockholders-pro forma.........     $(29,370,094)     $(5,679,620)

Net loss per common share-as reported........................     $      (2.97)     $     (3.07)

Net loss per common share-pro forma..........................     $      (2.97)     $     (3.42)

</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 60%; risk-free interest rate
of 5.71% in 1998 and 1997; and expected lives of five (5) years.


                                       43

<PAGE>


         OPTION REPRICINGS - In the last quarter of 1997, the Company determined
to attempt to consummate a significant corporate transaction in order to satisfy
the Company's need for additional capital resources. In connection with pursuing
such a transaction, Mr. Berry and Mr. Christofferson entered into Incentive
Agreements and Contract Settlement Agreements with the Company pursuant to which
each of Mr. Berry and Mr. Christofferson were entitled to receive certain
Incentive Payments and Contract Settlement Payments upon the consummation of
such a transaction. The Acquisitions were such a transaction. Their employment
agreements terminated upon the consummation of the Acquisitions.

         In negotiating the terms of the Incentive Agreements and Contract
Settlement Agreements, Mr. Berry and Mr. Christofferson determined that their
existing stock options would expire 90 days after their termination of
employment. The Compensation Committee of the Board of Directors which was
comprised of Messrs. Sweeny and Elliott, each of whom was an outside director,
recognized that the expiration of those options would result in a disincentive
for Mr. Berry and Mr. Christofferson to help the Company pursue a significant
corporate transaction. Therefore, the Compensation Committee determined that Mr.
Berry's and Mr. Christofferson's existing stock options should be canceled and
replaced with new stock options that would terminate not sooner than the date
their old options would have expired if their employment with the Company was
not terminated. As an added incentive, the Compensation Committee determined to
reprice Mr. Berry's and Mr. Christofferson's options so they could more readily
benefit from any upturn in the Company's Common Stock trading price upon the
consummation of a significant corporate transaction.

         When determining the price at which Mr. Berry's and Mr.
Christofferson's new options would be exercisable, the Compensation Committee
took the average closing price of the Company's Common Stock on the NASDAQ
Small-Cap Market over the 20 day trading period immediately preceding the option
reprice date, and multiplied such average trading price by 65%. The Compensation
Committee believed that the discount to the average trading price was
appropriate because the shares of Common Stock issuable upon exercise of the
repriced options would not be freely tradable and the discount was appropriate
to reflect the actual fair market value of the liquid shares that would be
received upon the exercise of the new options.

         The following table sets forth certain information with respect to
replacement stock options granted to Mr. Berry and Mr. Christofferson during the
year ended December 31, 1997, which are also reported above under "Option
Grants." There were no replacement stock options issued in 1998.

<TABLE>
<CAPTION>
                                                                                                                     Length of
                                                   Number of                                                        Original Option
                                                  Securities of                                                    Term Remaining
                                                  Underlying      Market Price of     Exercise Price      New       At Date of
                                                  Options/sars    Stock At Time of      At Time of      Exercise    Repricing or
                                                  Repriced Or     Repricing or       Repricing or       Price        Amendment
      Name                               Date       Amended         Amendment          Amendment                      (Months)
      ----                               ----     -----------     -------------      -------------     ---------    -----------
                                                                                                                 
<S>                                      <C>          <C>             <C>                 <C>            <C>              <C>
David W. Berry......................     12/3/97      20,000          $5.82               $ 9.72         $3.78            102
    President and                        12/3/97       4,000          $5.82               $18.60         $3.78             69
    Chief Executive Officer
David B. Christofferson.............     12/3/97      30,000          $5.82               $10.08         $3.78             62
    Executive Vice                       12/3/97       4,000          $5.82               $18.60         $3.78             69
    President, General                   12/3/97      16,667          $5.82               $ 8.82         $3.78            102
    Counsel and Secretary

</TABLE>


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

         The Company sold various properties in a number of different
transactions during 1998 and 1997. These sales resulted in an aggregate gain of
approximately $485,813 for 1997. No gain or loss was recorded on the sale of gas
and oil assets in 1998 as these were the sale of partial interests in several
unproved properties and the proceeds were treated as a recovery of costs.


                                       44

<PAGE>


5.       LONG-TERM DEBT:

         Long-term debt consists of the following:

<TABLE>
<CAPTION>

                                                                                                            December 31,
                                                                                                     -------------------------
                                                                                                        1998         1997
                                                                                                        -----        ----
<S>                                                                                                  <C>           <C>        
Note payable repaid in 1998.......................................................................   $             $   274,922
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect,
 interest accrued at 15%..........................................................................      864,000         64,000

Note payable to bank, interest at 7.49% to 12.5%, payable in monthly
 installments, collateralized by other property and equipment.....................................        1,236         48,843
Note payable, interest at 12%, payable monthly, is currently due..................................      100,000        100,000
Loan with B of A, in two Tranches:  Tranche A is a revolving credit facility
which terminates October 13, 2000, thereafter converting the unpaid balance
into a five year term loan requiring quarterly principle and interest payments;
Tranche B is payable in interest only until maturity on April 13, 2000, at which
time payment in full is required. Both loans are at a varied interest rate
utilizing either the B of A's Alternative Reference Rate (Alternative Reference
Rate is the greater of (i) B of A's Reference Rate and (ii) the Federal Funds
effective rate plus 0.50%) or the Interbank rate plus 2% for Tranche A and 4% for
     Tranche B. The loan is secured by a mortgage on all properties currently
     owned by the Company.........................................................................    7,500,000            --
                                                                                                     ----------    ----------
                                                                                                      8,465,236     1,287,765
Less current portion..............................................................................      101,236       401,085
                                                                                                     ----------    ----------
                                                                                                     $8,364,000    $  886,680
                                                                                                     ----------    ----------
                                                                                                     ----------    ----------
</TABLE>


         Maturities of long-term debt (excluding non-recourse debt, which is
solely dependent upon the successful development and future production, if any,
of the Starboard Prospect) are as follows:

<TABLE>
<CAPTION>


Year                               At December 31, 1998
-----                              --------------------
<S>                                   <C>       
1999...............                   $  101,236
2000...............                    4,412,500
2001...............                      650,000
2002...............                      650,000
2003...............                      650,000

</TABLE>


       The remaining balance of $1,137,500 will be paid in 2004 and 2005.


                                       45

<PAGE>


         On October 13, 1998, the Company amended and restated the credit 
agreement dated January 3, 1996 with B of A to an amount equal to the lesser 
of the Collateral Value, or $20,000,000. The amended agreement provided for 
an immediate borrowing base of up to $9,000,000 ($8,250,000 if the Company 
did a third party financing in which the third party lender would share in 
certain collateral of B of A). The $9,000,000 base represents the Collateral 
Value until the initial Collateral Value Redetermination is made. The Company 
has drawn $7,500,000 pursuant to the B of A facility. The loan is in two 
tranches. Tranche A is a revolving facility which terminates on October 13, 
2000 thereafter converting the unpaid balance into a five year term loan 
requiring quarterly principle and interest payments. Tranche B is payable in 
interest only until maturity on April, 13, 2000 at which time payment in full 
is required. In conjunction with this financing, B of A received a 2% 
overriding royalty interest, proportionately reduced to the Company's net 
interest, in the properties classified proven as of the date of closing and 
received a five year warrant to purchase 95,000 shares of common stock at a 
price equal to the average daily closing price of the Company's common stock 
for the thirty days prior to closing of the credit agreement. Proceeds of the 
loan primarily supplement working capital. As part of the credit agreement, 
the Company is subject to certain covenants and restrictions, among which are 
the limitations on additional borrowing, and sales of significant properties, 
working capital, cash, and net worth maintenance requirements and a minimum 
debt to net worth ratio. The covenants regarding financial condition of 
Company are as follows:

<TABLE>

<S>                                     <C>
  Tangible Net Worth................... $45,000,000 + 50% of Consolidated Net Income + 100% of net
                                        proceeds received from sale of any Non-Redeemable Stock
  Current Ratio........................ 1.1:1.0
  Debt to Capitalization............... 0.5:1.0
  Interest Coverage Ratio ............. 1.0:1.0 - 4th quarter 1998 and 1st quarter 1999, 3.0:1.0 2nd qtr 1999
                                        and any consecutive quarters after June 30, 1999

</TABLE>


         At December 31, 1998 the Company's tangible net worth as calculated 
pursuant to the Credit Agreement was $35,322,586. B of A has waived 
noncompliance with this covenant at December 31, 1998 and March 31, 1999. The 
Company and B of A have been in discussions, both recognizing that the 
covenant as initially established did not give adequate consideration to the 
effects of the Company's successful efforts method of accounting on the 
future book value of its properties, in particular the accounting treatment 
that the Company has adopted which requires the amortization over a period 
not to exceed forty-eight months of a substantial portion of the property 
values recorded pursuant to the Acquisitions. As such, B of A has agreed with 
the Company in concept to reduce the tangible net worth requirement to an 
amount not in excess of $25,000,000, subject to approval of B of A's credit 
committee anticipated in the second quarter of 1999. In the event the credit 
committee does not approve the modification of the covenant, the Company 
would be in noncompliance of this provision and will seek alternative 
financing arrangements.

         Further as of December 31, 1998, the Company's current ratio was 
0.3128:1 and the Company's interest coverage ratio was (2.1368) to 1, both of 
which were, therefore, in noncompliance. B of A has waived said noncompliance 
at December 31, 1998. The Company believes it has improved its current ratio 
and its interest coverage ratio since December 31, 1998 significantly; 
however, it does not believe it is likely that it will be in compliance with 
either of said covenants as of March 31, 1999. B of A has indicated that, in 
the event the Company is in noncompliance, it will likely waive any such 
covenants through April 1, 1999. Although the Company believes it can be in 
compliance with both of these covenants throughout the remainder of 1999, 
there can be no assurance

                                       46

<PAGE>


that it will be in compliance. As a result it is possible that additional
waivers may be needed in the future. In the event B of A did not grant such
waivers, if needed, the Company would be in noncompliance of the covenants and
would seek alternative financing arrangements.

         In addition, the Company has entered into an interest rate swap 
guaranteeing a fixed interest rate of 8.28% on the loan, and the Company will 
pay fees of one-eighth of 1% (.0125%) on the unused portion of the commitment 
amount. The unrealized loss on the interest rate swap agreement was $21,910 
and $1,275 at December 31, 1997 and 1998, respectively.

         On March 12, 1996, the Company completed a financial package with a
group funded by a public utility to evaluate and develop a project in Terrebonne
Parish, Louisiana. This group will participate in 48% of all costs of evaluation
and development of the project area and provided a non-recourse loan to fund the
Company's 48% share of the leasehold and seismic evaluation costs of the
project. The loan is secured by a mortgage on the Company's interest in the
project. As of December 31, 1998 and 1997, the Company has received advances
aggregating $864,000 on the non-recourse loan. The non-recourse loan will be
paid solely by the assignment on an 8% overriding royalty interest in the future
revenues of the financed project. Future funding will be provided as costs are
incurred.

6.       INCOME TAXES:

         Deferred tax assets and liabilities are as follows:


<TABLE>
<CAPTION>

                                                    At December 31,
                                                1998            1997
                                                ----            ----
<S>                                            <C>              <C>        
Net operating tax loss carryforward.........   $ 11,633,159     $ 4,332,710
Property and equipment......................       (435,246)     (2,936,284)
Valuation allowance.........................    (11,197,913)     (1,396,426)
                                               -----------      -----------
    Net deferred tax asset (liability)......   $         --     $        --
                                               -----------      -----------

</TABLE>


         The Company has recorded a deferred tax valuation allowance since, 
based on an assessment of all available historical evidence, it is more 
likely than not that future taxable income will not be sufficient to realize 
the tax benefit. The Company and its subsidiaries have net operating loss 
carryforwards ("NOLs") at December 31, 1998, of approximately $33,200,000 
which may be used to offset future taxable income. The operating loss 
carryforwards expire in the tax years 2006 through 2018.

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

7.       RELATED PARTY TRANSACTIONS:

         The Company's outstanding advances to employees and affiliates of 
the Company at December 31, 1998 and 1997 was $963,700 and $105,171, 
respectively. The December 31, 1998 and 1997 receivables include 
approximately $47,787 from an affiliated partnership for which the Company 
serves as the managing general partner. In addition, the December 31, 1998 
balance includes a $915,342 receivable from Esenjay Petroleum (EPC) primarily 
related to joint interest billings to EPC. In addition, amounts payable of 
$134,400 and $112,000 were due to David W. Berry and David B Christofferson, 
respectively, in conjunction with the settlement of their prior employment 
contracts. In addition, at December 31, 1998 the Company had a net account 
payable to Aspect in the amount of $4,322,548. (See Note 9)

                                       47

<PAGE>


8.       COMMITMENTS AND CONTINGENCIES:

         The Company leases office space under lease agreements, which are
classified as operating leases. Lease expense under these agreements was
$193,515 in 1998 and $112,432 in 1997. A summary of future minimum rentals on
these non-cancelable operating leases is as follows:


<TABLE>
<CAPTION>

              Year                       At December 31, 1998
             ------                     ---------------------
              <S>                           <C>     
              1999...................       $252,514
              2000...................       $252,514
              2001...................       $213,491
              2002...................       $135,446
              2003...................       $ 67,723

</TABLE>


         The Company is party to various lawsuits arising in the normal course
of business. Management believes the ultimate outcome of these matters will not
have a material effect on the Company's consolidated financial position, results
of operation, and net 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. During January 1999, the Company completed performance on a
1996 swap agreement on approximately 1,040 MMBtu's per day of Mid-Continent
natural gas production for $1.566 per MMBtu for the period beginning April 1,
1996 and ending January 31, 1999.

         In October of 1998, the Company entered into two swap agreements, one
on 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.14 per
MMBtu for the period beginning November 1998 and ending in October 1999, and the
second one on 700 MMBtu's per day of its Gulf Coast natural gas production for
$2.13 per MMBtu for the period beginning November 1998 and ending in October
1999. Both of these swap agreements were supplemented in December 1998 when the
Company entered into additional swap agreements, one of which was for 4,000
MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for
the period beginning November 1999 and ending in October 2000, and the second
one was on 700 MMBtu's per day of its Gulf Coast natural gas production for
$2.07 per MMBtu for the period beginning November 1999 and ending in October
2000. As a result of the foregoing transactions, the Company has 4,700 MMBtu's
per day of its Gulf Coast natural gas production hedged through October 2000.

9.       ACQUISITIONS:

         On May 14, 1998, the Company acquired substantial interests in 28
exploration projects from EPC and Aspect in exchange for 10,106,700 shares of
the Company's common stock. The estimated fair value on the date of acquisition
was approximately $60 million, which consists of the fair market value of $54.2
million, as determined by an independent third party, plus project costs from
the effective date of November 1, 1997 up to the closing of the Acquisition
Agreement. The acquired projects are primarily technology enhanced natural gas
exploration projects along the Texas and Louisiana Gulf Coast.

         The Acquisitions have been recorded at their fair value and have been
included in the Company's consolidated financial statements from the date of
their acquisition. The following unaudited pro forma information presents a
summary of condensed consolidated results of operations as if the Acquisitions
had occurred on January 1, 1997:


                                       48

<PAGE>


<TABLE>
<CAPTION>

                                                                       Year ended
                                                                       December 31,
                                                              -----------------------------
                                                                 1998             1997
                                                              -------------   -------------
<S>                                                           <C>             <C>        
   Revenues.................................................  $  1,716,473    $    908,609
   Total costs and expenses.................................   (33,325,677)    (12,865,085)
                                                              -------------   -------------
   Net loss.................................................  $(31,609,204)   $ 11,956,476
                                                              -------------   -------------
                                                              -------------   -------------
   Basic and diluted loss per share.........................  $      (2.33)   $      (1.02)
                                                              -------------   -------------
                                                              -------------   -------------

</TABLE>


10.      PROPERTY AND EQUIPMENT

<TABLE>
<CAPTION>
                                                                 Year ended December 31,
                                                                ------------------------
                                                                   1998          1997
                                                                -----------   ----------
         <S>                                                    <C>           <C>
         Gas and oil properties, at cost , successful
           efforts method of accounting:
               Proved .........................................  14,006,244    1,181,811
               Unproved, subject to amortization ..............  43,800,198           --
               Unproved, not subject to amortization ..........  10,835,056    2,054,037
                                                               ------------   ----------
                  Total gas and oil properties ................  68,641,498    3,235,848
         Other property and equipment .........................   1,403,384    1,169,127
                                                               ------------   ----------
                  Total property and equipment ................  70,044,882    4,404,975
         Less accumulated depletion, depreciation and 
           amortization........................................ (15,517,656)  (1,260,605)
                                                               ------------   ----------
                  Total property and equipment, net............$ 54,527,226   $3,144,370
                                                               ------------   ----------
                                                               ------------   ----------


</TABLE>


11.      SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED):

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

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

         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,
                                                                              -----------------------
                                                                            1998                    1997
                                                                            ----                    ----
<S>                                                                    <C>                      <C>       
Acquisition of properties:
    Proved....................................................         $         --             $  765,678
    Unproved..................................................           63,511,000                242,205
Exploration costs.............................................           13,412,133              1,861,432
Development costs.............................................            7,114,820                153,938
                                                                        -----------             ----------
        Total costs incurred..................................          $84,037,952             $3,023,253
                                                                        -----------             ----------
                                                                        -----------             ----------

</TABLE>


                                       49

<PAGE>


CAPITALIZED COSTS:

<TABLE>
<CAPTION>

                                                                                       At December 31,
                                                                                       ---------------
                                                                                    1998           1997
                                                                                    ----           ----
<S>                                                                             <C>             <C>       
Proved......................................................................... $ 14,006,244    $1,181,811
Unproved properties, subject to amortization...................................   43,800,198            --
Unproved properties not being amortized........................................   10,835,056     2,054,037
Less accumulated amortization..................................................  (14,584,784)     (438,044)
                                                                                -----------     -----------
                 Net capitalized costs......................................... $ 54,056,714    $2,797,804
                                                                                -----------     -----------
                                                                                -----------     -----------
</TABLE>



ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:

         The estimates of proved producing reserves were estimated. Proved
reserves cannot be measured exactly because the estimation of reserves involves
numerous judgmental and arbitrary determinations. Accordingly, reserve estimates
must be continually revised as a result of new information obtained from
drilling and production history or as a result of changes in economic
conditions.


<TABLE>
<CAPTION>

                                                                                                  Crude Oil, Condensate and Natural
                                                                                                             Gas Liquids 
                                                                Natural Gas (Mcf)                             (Barrels)
                                                                ----------------                              ---------
                                                             Years Ended December 31,                   Years Ended December 31,
                                                             --------------------------                 ------------------------
                                                             1998                  1997                   1998            1997
                                                            -----                  -----                  ----            -----
<S>                                                        <C>                   <C>                     <C>            <C>    
Proved developed and undeveloped reserves:
    Beginning of period .......................            5,500,363             8,901,555               114,399        183,735
    Purchases of minerals-in-place ............                   --                    --                    --             --
    Sales of minerals-in-place ................                   --              (159,528)                   --         (3,857)
    Revisions of previous estimates ...........           (5,284,456)           (3,129,076)              (97,420)       (59,121)
    Extensions, discoveries and other additions           12,367,076                 8,716                92,094            928
    Production ................................             (653,316)             (121,304)               (8,878)        (7,286)
                                                          ----------            ----------              --------        --------
    End of period .............................           11,929,667             5,500,363               100,195         114,399
                                                          ----------            ----------              --------        --------
                                                          ----------            ----------              --------        --------
Proved developed reserves:
    Beginning of period .......................              521,345               985,524                24,358          46,420
    End of period .............................            6,864,564               521,345                59,085          24,358

</TABLE>


         Reserves of wells, which have performance history, were estimated
through analysis of production trends and other appropriate performance
relationships. Where production and reservoir data were limited, the volumetric
method was used and it is more susceptible to subsequent revisions.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:

         The standardized measure of discounted future net cash flows is based
on criteria established by Financial Accounting Standards Board Statement No.
69, "Accounting for Oil and Gas Producing Activities" and is not intended to be
a "best estimate" of the fair value of the Company's oil and gas properties. For
this to be the case, forecasts of future economic conditions, varying price and
cost estimates, varying discount rates and consideration of other than proved
reserves (i.e., probable reserves) would have to be incorporated into the
valuations. 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. Average year
end prices used in determining future cash inflows for natural gas and oil for
the periods ended December 31, 1998 and 1997 were as follows: 1998 - $2.01 per
MCF-Gas, $9.03 per barrel-Oil; 1997 - $2.46 per MCF-Gas, $15.70 per barrel-Oil,
respectively. Future net cash flows are then calculated by reducing such
estimated cash inflows by the


                                       50

<PAGE>


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,
                                                                      --------------------------
                                                                      1998                    1997
                                                                      ----                    ----
<S>                                                               <C>                    <C>         
Future cash inflows ....................................          $ 25,241,119           $ 15,752,040
Future development and production costs ................            (8,478,613)            (7,468,887)
Future income tax expenses .............................                    --               (365,224)
                                                                  ------------           ------------
Future net cash flows ..................................            16,762,506              7,917,929
Discount ...............................................            (4,242,485)            (4,019,429)
                                                                  ------------           ------------
Standardized measure of discounted future net cash flows          $ 12,520,021           $  3,898,500
                                                                  ------------           ------------
                                                                  ------------           ------------

</TABLE>

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

<TABLE>
<CAPTION>

                                                                                          Year Ended December 31,
                                                                                      1998                     1997
                                                                                      ----                     ----
<S>                                                                               <C>                   <C>         
Standardized measure of discounted future cash flows-beginning of period          $ 3,898,500           $ 16,758,544
Sales of oil and gas produced, net of operating expenses ...............           (1,021,830)              (312,198)
Net changes in sales prices and production costs .......................           (4,459,331)           (10,601,580)
Extensions, discoveries and improved recovery, less related costs ......           13,358,762                 30,952
Change in future development costs .....................................            5,135,315               (433,314)
Previously estimated development costs incurred during the year ........                2,515                162,610
Revisions of previous quantity estimates ...............................           (1,957,356)            (4,973,603)
Accretion of discount ..................................................              402,566              2,169,632
Net change of income taxes .............................................              127,157              4,810,619
Sales of minerals-in-place .............................................                   --               (371,728)
Changes in production rates (timing) and other .........................           (2,966,277)            (3,341,614)
                                                                                  ------------           ------------
Standardized measure of discounted future cash flows-end of period.......         $12,520,021            $ 3,898,500
                                                                                  ------------           ------------
                                                                                  ------------           ------------

</TABLE>




                                       51

<PAGE>


                            ESENJAY EXPLORATION, INC.


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

         Not Applicable.




                                       52

<PAGE>


                           ESENJAY EXPLORATION, INC.


                                    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 partially 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.

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.

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.


                                       53

<PAGE>


                                     PART IV

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

<TABLE>
<CAPTION>

Exhibit       Name of Exhibit
-------       ---------------
<S>           <C>
2(a)          Acquisition Agreement and Plan of Exchange dated as of January 19,
              1998, by and among Frontier Natural Gas Corporation, Esenjay
              Petroleum Corporation, and Aspect Resources LLC 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 2.

2(b)          First Amendment to Acquisition Agreement and Plan of Exchange
              dated as of April 20, 1998, by and among Frontier Natural Gas
              Corporation, Esenjay Petroleum Corporation, and Aspect Resources
              LLC as incorporated by reference to the Company's Registration
              Statement number 333-53581 dated May 21, 1998 wherein the same
              appeared as Exhibit 10(x).

2(c)          Second Amendment to Acquisition Agreement and Plan of Exchange
              dated as of May 13, 1998, by and among Frontier Natural Gas
              Corporation, Esenjay Petroleum Corporation, and Aspect Resources
              LLC as incorporated by reference to the Company's Registration
              Statement number 333-53581 dated May 21, 1998 wherein the same
              appeared as Exhibit 10(y).

2(d)          Plan and Agreement of Merger dated as of May 14, 1998, by and
              between Esenjay Exploration, Inc., a Delaware corporation, and
              Frontier Natural Gas Corporation as incorporated by reference to
              the Company's Proxy Statement filed with the Securities and
              Exchange Commission on April 24, 1998, wherein the same appeared
              as Appendix F.

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             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)         Contract Settlement Agreement between Frontier Natural Gas
              Corporation and David W. Berry dated effective January 1, 1998, 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(b).

10(b)         Contract Settlement Agreement between Frontier Natural Gas
              Corporation and David B Christofferson dated effective January 1,
              1998, 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(d).

10(c)*        $20,000,000 Amended and Restated Credit Agreement dated as of
              October 13, 1998, between Esenjay Exploration, Inc. as the
              borrower and Bank of America NT&SA as the lender.

10(d)*        Credit Agreement by and between Esenjay Exploration, Inc. and Duke
              Energy Financial Services, Inc. dated as of January 28, 1999, as
              currently in effect.

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

</TABLE>


                                       54

<PAGE>

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

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

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

10(j)         Warrant Agreement between Frontier Natural Gas Corporation and
              Gaines, Berland Energy Fund, L.P. dated January 23, 1998, as
              incorporated by reference to the Company's Registration Statement
              number 333-53581 dated May 21, 1998 wherein the same appeared as
              Exhibit 10(t).

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

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

11*           Statement of Earnings per Share
21*           Subsidiaries of Registrant.
27*           Financial Data Schedule.
(b)           Reports on Form 8-K. None

</TABLE>


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


                                       55

<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 14, 1999             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 14, 1999             /s/ David B Christofferson
                                  --------------------------
                                  David B Christofferson, Senior Vice President
                                  General Counsel and Chief Financial Officer


Date:  April 14, 1999             /s/ Howard E. Williams
                                  ----------------------
                                  Howard E. Williams, Vice President and 
                                  Principal Accounting Officer


Date:  April 14, 1999             /s/ David W. Berry
                                  ----------------------
                                  David W. Berry, Chairman and Director


Date:  April 14, 1999             /s/ Charles J. Smith
                                  --------------------
                                  Charles J. Smith, Director


Date:  April 14, 1999             /s/ Alex M. Cranberg
                                  --------------------
                                  Alex M. Cranberg, Director


Date:  April 14, 1999             /s/ Alex B. Campbell
                                  --------------------
                                  Alex B. Campbell, Director


Date:  April 14, 1999             /s/ Jack P. Randall
                                  -------------------
                                  Jack P. Randall, Director


Date:  April 14, 1999             /s/ William D. Dodge
                                  --------------------
                                  William D. Dodge, Director


Date:  April 14, 1999             /s/ Hobart A. Smith
                                  -------------------
                                  Hobart A. Smith, Director


                                       56