<PAGE>
4,000,000 SHARES
[LOGO]
COMMON STOCK
The 4,000,000 shares of common stock, par value $.01 per share ("Common
Stock"), offered hereby (the "Offering") are being sold by Esenjay Exploration,
Inc., a Delaware corporation (the "Company").
The Common Stock is quoted on the Nasdaq Small-Cap Market under the symbol
"ESNJ." On July 15, 1998, the closing price of the Common Stock, as reported by
the Nasdaq Small-Cap Market, was $4.125 per share.
Aspect Resources LLC ("Aspect") and Esenjay Petroleum Corporation ("EPC"),
affiliates of the Company, and David Berry, the Chairman of the Board of the
Company, have agreed to purchase an aggregate of 350,000 shares of the Common
Stock offered hereby. See "Summary--The Offering", "Principal Stockholders" and
"Underwriting."
------------------------
THESE ARE SPECULATIVE SECURITIES. FOR A DISCUSSION OF CERTAIN MATERIAL
FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON
STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 10.
---------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS(1)(2) COMPANY(2)(3)(4)
<S> <C> <C> <C>
Per Share.............................................. $4.00 $0.28 $3.72
Total (3).............................................. $16,000,000 $1,120,000 $14,880,000
</TABLE>
(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended (the "Securities Act"). Does not reflect additional compensation to
the Representative of the Underwriters (the "Representative") in the form of
(i) a nonaccountable expense allowance of $300,000 and (ii) warrants to
purchase up to 210,000 shares of Common Stock at an exercise price of $7.20
per share. See "Underwriting."
(2) The Underwriters and the Company have agreed that $14,000 of the
underwriting discount attributable to the Common Stock being purchased by
Aspect, EPC and Mr. Berry will be reimbursed to the Company, thereby
increasing the Company's proceeds from this Offering by such amount.
(3) Before deducting offering expenses payable by the Company, estimated to be
$350,000.
(4) The Company has granted the Underwriters a 30-day option to purchase up to
600,000 additional shares of Common Stock, solely to cover over-allotments,
if any, upon the same terms and conditions as the shares offered hereby. If
such over-allotment option is exercised in full, the total Price to Public,
Underwriting Discounts and Commissions and Proceeds to Company will be
$18,400,000, $1,288,000 and $17,112,000, respectively. See "Underwriting."
------------------------
The shares of Common Stock are offered by the several Underwriters named
herein, subject to receipt and acceptance by them and subject to their right to
reject any order in whole or in part. It is expected that delivery of such
shares will be made at the offices of Gaines, Berland Inc., New York, New York,
on or about July 21, 1998.
GAINES, BERLAND INC.
THE DATE OF THIS PROSPECTUS IS JULY 16, 1998.
<PAGE>
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING OVER-ALLOTMENT, STABILIZING AND SHORT-COVERING TRANSACTIONS IN SUCH
SECURITIES, AND THE IMPOSITION OF A PENALTY BID IN CONNECTION WITH THE OFFERING.
IN ADDITION, CERTAIN UNDERWRITERS (INCLUDING SELLING GROUP MEMBERS, IF ANY) ALSO
MAY ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON THE
NASDAQ SMALL-CAP MARKET IN ACCORDANCE WITH RULE 103 OF REGULATION M UNDER THE
SECURITIES EXCHANGE ACT OF 1934. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE
"UNDERWRITING."
2
<PAGE>
SUMMARY
THE FOLLOWING SUMMARY SHOULD BE READ IN CONJUNCTION WITH, AND IS QUALIFIED
IN ITS ENTIRETY BY THE MORE DETAILED INFORMATION AND FINANCIAL STATEMENTS
(INCLUDING THE NOTES THERETO) APPEARING ELSEWHERE IN THIS PROSPECTUS. ON MAY 14,
1998, THE COMPANY CONSUMMATED A ONE-FOR-SIX REVERSE SPLIT OF THE COMPANY'S
COMMON STOCK (THE "REVERSE SPLIT"). ALL PER SHARE DATA SET FORTH HEREIN, UNLESS
OTHERWISE INDICATED, HAVE BEEN ADJUSTED TO REFLECT THE REVERSE SPLIT. UNLESS
OTHERWISE INDICATED, THE INFORMATION IN THIS PROSPECTUS ASSUMES THE
UNDERWRITERS' OVER-ALLOTMENT OPTION WILL NOT BE EXERCISED. INVESTORS SHOULD
CAREFULLY CONSIDER THE INFORMATION SET FORTH UNDER THE HEADING "RISK FACTORS,"
BEGINNING ON PAGE 10. REFERENCES HEREIN TO THE "COMPANY" MEAN ESENJAY
EXPLORATION, INC., A DELAWARE CORPORATION, FORMERLY KNOWN AS FRONTIER NATURAL
GAS CORPORATION. CERTAIN TERMS USED HEREIN RELATING TO THE OIL AND NATURAL GAS
INDUSTRY ARE DEFINED IN A GLOSSARY OF CERTAIN INDUSTRY TERMS INCLUDED ELSEWHERE
IN THIS PROSPECTUS.
THE COMPANY
OVERVIEW
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 over 30 technology enhanced natural gas 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"). Cornerstone Ventures, L.P.,
a Houston, Texas, based investment banking firm with expertise in evaluating the
value of oil and gas exploration properties ("Cornerstone"), delivered to the
Company a written opinion that estimated the fair market value of the assets
acquired in the Acquisitions, as of January 23, 1998, to be $54.2 million. See
"Risk Factors--Uncertainty as to Estimates of Fair Market Values." The
Exploration Projects also include the Company's interest in the Starboard
Project in Terrebonne Parish, Louisiana, which consists of mineral leases and
options and a proprietary 3-D seismic survey over the Lapeyrouse Field. The
Company, EPC and Aspect have spent several years identifying and evaluating many
of the Exploration Projects.
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, EPC, Aspect and
the Enron affiliate own 43.91%, 36.27% and 5.74%, respectively, of the Company's
Common Stock.
Most of the Exploration Projects have been, are being, or will be enhanced
with 3-D seismic data in conjunction with computer aided exploration ("CAEX")
technologies. The 3-D seismic data acquired, when complete, will cover
approximately 1,500 square miles. A significant number of the Exploration
Projects have reached the drilling stage, and the Company has budgeted
approximately $25.0 million, in addition to funds already spent, to fund the
drilling of approximately 30 wells and to fund other exploration costs over the
next 12 months. The Company believes that the Exploration Projects represent a
diverse array of technology enhanced, 3-D seismic confirmed, ready to drill
natural gas exploration projects.
From November 1, 1997 (the effective date of the Acquisitions) through the
date hereof, approximately $4.91 million has been spent for the Company's
account on drilling and completion costs on the Exploration Projects. The
expenditures have funded costs of the Company's interests in 15 exploratory
wells, of which six have been completed, four are awaiting completion and five
were dry holes.
3
<PAGE>
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, landmen and other
technical personnel. After the Acquisitions, the Company hired most of EPC's
technical personnel, who, in some instances, have worked together for over
15 years. In addition, the Company has entered into a geotechnical services
consulting agreement with Aspect on certain of the Exploration Projects
pursuant to which Aspect provides 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 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.
4
<PAGE>
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 most cases, the
Company owns a greater interest than any of its project partners. As a
result, in most of its Exploration Projects, the Company will 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 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 in South Texas. The remaining
Exploration Projects consist of the Starboard Project, as well as other projects
in Texas, 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 (the
"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 the Company will own when any 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. For further information, see "Business and
Properties--Exploration Projects."
5
<PAGE>
EXPLORATION PROJECTS
<TABLE>
<CAPTION>
ACRES LEASED OR
UNDER OPTION AT
MAY 15, 1998(1) SQUARE MILES OF 3-D
----------------------- SEISMIC DATA RELATING PROJECT
PROJECT AREAS GROSS NET TO PROJECT AREA(2) INTEREST
- ----------------------------------------------- --------- ------------ ----------------------- ---------------
<S> <C> <C> <C> <C>
SOUTH TEXAS
DOWNDIP FRIO CORE AREA
Big Gas Sand................................. 24,700 5,557 65 22.5%
Blessing..................................... 10,672 2,471 22 24.0%
Tidehaven.................................... 9,145 1,742 28 40.5%
El Maton..................................... 7,277 3,044 29 46.5%
Midfield..................................... 2,228 569 21 37.5%
Matagorda I(3)............................... 11,444 6,879 50 74.0%
Matagorda II(4).............................. 7,480 3,859 60 66.0%
Southwest Pheasant........................... 10,000 7,500 10 75.0%
Geronimo..................................... 9,616 1,792 76 20.0%
Houston Endowment............................ 3,969 1,071 50 27.0%
Wolf Point................................... 1,520 546 8 45.5%
Sheriff Field................................ 54,000 40,500 72 75.0%
West Jeffco.................................. 13,500 6,075 60 45.0%
La Rosa...................................... 7,689 589 25 8.0%
Piledriver................................... 640 400 2 62.5%
WILCOX CORE AREA
Hall Ranch................................... 8,510 3,521 57 41.5%
Hordes Creek................................. 6,972 2,601 25 41.5%
Mikeska...................................... 7,239 2,490 31 38.0%
Duval, McMullen.............................. 1,979 1,781 12 90.0%
TEXAS HACKBERRY CORE AREA
Lox B........................................ 11,700 2,925 71 25.0%
West Port Acres.............................. 800 100 21 12.5%
Big Hill/Stowell............................. 10,000 5,000 56 50.0%
East Jeffco.................................. 24,000 12,000 65 50.0%
West Beaumont................................ 11,200 700 23 6.25%
LOUISIANA
Starboard.................................... 6,682 5,905 35 12.0%-48.0%
Tack......................................... 480 300 12 75.0%
OTHER TEXAS
Willacy County............................... 11,485 8,784 50 78.875%
Caney Creek.................................. 21,000 2,625 32 12.5
East Texas Pinnacle Reef (5)................. -- -- 400 --
MISSISSIPPI
Thompson Creek............................... 1,325 512 12 56.0%
Lipsmacker................................... 5,758 943 64 22.0%
--------- ------------ ------
Total...................................... 303,010 132,781 1,544
--------- ------------ ------
--------- ------------ ------
</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) Represents 3-D seismic data acquired or to be acquired. See "Business and
Properties--Exploration Projects--Exploration Project Descriptions."
(3) The Company has entered into an agreement to sell a 26.7% Project Interest
in this Exploration Project for $694,200 for costs incurred before
commencement of drilling operations.
(4) The Company has entered into an agreement to sell a 26.7% Project Interest
in this Exploration Project for $694,200 for costs incurred before the
commencement of drilling operations.
(5) Consists of 400 square miles of 3-D seismic data to which Aspect has rights
pursuant to a license agreement, and in which the Company may acquire an
interest pursuant to a geophysical technical services consulting agreement
with Aspect.
6
<PAGE>
The Company was originally incorporated in Oklahoma on February 1, 1993. On
May 14, 1998, the Company reincorporated in Delaware. The Company's principal
executive offices are located at 500 North Water Street, Suite 1100, Corpus
Christi, Texas 78471, and its telephone number at such address is (512)
883-7464. The Company also maintains corporate finance and business development
offices at One Allen Center, Suite 2920, Houston, Texas 77002, and its telephone
number at such address is (713) 739-7100.
THE OFFERING
<TABLE>
<S> <C>
Common Stock offered.............. 4,000,000 shares. Aspect, EPC and David W. Berry,
Chairman of the Board of the Company, have agreed to
purchase an aggregate of 350,000 shares of Common Stock
in this Offering. See "Principal Stockholders" and
"Underwriting."
Common Stock outstanding after the
Offering(1)..................... 15,762,687 shares
Use of Proceeds................... To repay $7.8 million of indebtedness, for exploration
and development activities and for working capital. See
"Use of Proceeds."
Nasdaq Small-Cap Market Symbol.... ESNJ
</TABLE>
- ------------------------
(1) Does not include (i) up to 600,000 shares of Common Stock issuable pursuant
to the Underwriters' over-allotment option; (ii) 291,667 shares of Common
Stock issuable upon conversion of the Company's Series A Warrants; (iii)
776,250 shares of Common Stock issuable upon the exercise of the Company's
Series B Warrants; (iv) 595,833 shares of Common Stock issuable upon the
exercise of additional outstanding warrants, including warrants to purchase
210,000 shares of Common Stock issued to the Representative in connection
with this Offering (the "Representative's Warrant"); and (v) 104,000 shares
of Common Stock issuable upon the exercise of outstanding employee stock
options. See "Risk Factors--Shares Eligible for Future Sale;
Management--Option Grants" and "Underwriting."
RISK FACTORS
Prospective purchasers of Common Stock should carefully consider all of the
information contained in this Prospectus, particularly the factors set forth
under "Risk Factors" beginning on page 10.
7
<PAGE>
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
The summary financial data below sets forth (i) the historical financial
data as of and for the years ended December 31, 1996 and 1997 and the three
months ended March 31, 1997 and 1998; (ii) pro forma financial data giving
effect to the Acquisitions, the redemption of 85,961 shares of the Company's 12%
Cumulative Convertible Preferred Stock, par value $.01 per share (the "Preferred
Stock") which was called for redemption on May 14, 1998, and the use of proceeds
from the Company's credit facility with Duke Energy Financial Services, Inc.
(the "Duke Credit Facility"), as if each of such transactions had occurred on
January 1, 1997; and (iii) pro forma as adjusted financial data giving effect to
the use and application of the net proceeds of the sale of the Common Stock
offered hereby. The historical financial data are derived from the Company's
audited financial statements. The financial data as of and for the three month
period ended March 31, 1997 and 1998 are derived from the Company's unaudited
consolidated financial statements. The unaudited consolidated financial
statements include all adjustments, consisting of normal recurring accruals,
that the Company considers necessary for a fair presentation of the Company's
financial position as of such dates and the results of operations and cash flows
for such periods. Operating results for the three months ended March 31, 1998
are not necessarily indicative of the results that may be expected for the
entire year ending December 31, 1998. The statement of operations and balance
sheet data are provided for comparative purposes only and should be read in
conjunction with the Company's historical consolidated financial statements
included elsewhere in this Prospectus. The pro forma information presented is
not necessarily indicative of the combined financial results as they may be in
the future or as they might have been for the periods indicated had the
Acquisitions been consummated as of January 1, 1997.
<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS ENDED
DECEMBER 31, PRO FORMA MARCH 31, PRO FORMA
---------------------- DECEMBER 31, ---------------------- MARCH 31,
1996 1997 1997 1997 1998 1998
---------- ---------- ------------ ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues(1)............................... $3,166,792 $ 908,609 $ 908,609 $ 405,647 $ (16,586) $ (16,586)
Cost and expenses
Production and exploration costs(2)..... 2,450,771 3,065,394 8,585,067 1,048,502 60,197 1,316,964
Depletion, depreciation &
amortization(3)....................... 2,237,648 315,880 315,880 132,774 53,568 53,568
Impairment of oil and gas
properties(4)......................... 51,000 349,384 349,384 -- -- --
Interest expense(5)..................... 783,872 60,942 687,422 4,133 19,223 180,852
General and administrative
expenses(6)........................... 2,217,099 2,070,812 3,553,812 572,260 459,014 819,014
Other expenses(7)....................... 451,421 -- -- -- -- --
---------- ---------- ------------ ---------- ---------- ----------
Net income (loss)......................... (5,025,019) (4,953,803) (12,582,956) (1,352,022) (608,588) (2,386,984)
Cumulative preferred stock dividend....... 103,153 103,153 -- 25,788 25,788 --
---------- ---------- ------------ ---------- ---------- ----------
Net income (loss) applicable to common
shareholders............................ $(5,128,172) $(5,056,956) ($12,582,956) $(1,377,810) $ (634,376) $(2,386,984)
---------- ---------- ------------ ---------- ---------- ----------
---------- ---------- ------------ ---------- ---------- ----------
Net income (loss) per common share,
adjusted for 1:6 reverse stock split.... $ (4.31) $ (3.07) $ (1.07) $ (0.84) $ (0.38) $ (0.20)
---------- ---------- ------------ ---------- ---------- ----------
---------- ---------- ------------ ---------- ---------- ----------
Weighted average common shares
outstanding, adjusted for 1:6 reverse
stock split............................. 1,190,343 1,646,311 11,803,011 1,644,317 1,655,984 11,812,684
</TABLE>
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
--------------------------------------
PRO FORMA
HISTORICAL PRO FORMA AS ADJUSTED(8)
---------- ---------- --------------
<S> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit).............................................. $(1,148,584) $(3,124,406) $ 7,557,532
Properties and equipment, net.......................................... 3,491,694 60,691,695 60,691,695
Total assets........................................................... 6,359,392 62,523,730 71,540,477
Long-term debt (excluding current maturities).......................... 2,893,055 4,607,785 1,059,723
Stockholders' equity................................................... 1,203,024 53,429,136 67,317,771
</TABLE>
- ------------------------
Notes appear on following page.
8
<PAGE>
(1) Revenues decreased from $3.18 million for the year ended December 31, 1996
to $0.91 million for the same period of 1997, and from $0.41 million for the
three months ended March 31, 1997 to ($16,586) for the same period in 1998,
primarily as a result of ceased production from the Mobile Bay wells and
from the sale of producing properties. Negative revenues relate to the
effect of recognized losses on gas hedges in the quarter.
(2) Pro forma exploration costs include geological and geophysical, delay
rentals and exploration costs of $5.5 million and $1.3 million for the year
ended December 31, 1997 and for the three months ended March 31, 1998,
respectively, associated with the unproved prospects acquired from EPC and
Aspect pursuant to the Acquisition Agreement. Exploration costs for the
three months ended March 31, 1998 decreased $1.0 million from the same
period in 1997 due to dry holes drilled during 1997.
(3) Depletion, depreciation and amortization expense decreased from $2.2 million
for the year ended December 31, 1996 to $0.3 million for the same period in
1997, primarily due to the abandonment of previously producing wells in the
Mobil Bay prospect and the sale of certain oil and gas properties.
(4) Impairment of oil and gas properties increased from $51,000 in 1996 to
$349,384 in 1997 primarily due to the abandonment of previously producing
Mobile Bay wells.
(5) Interest expense decreased from $783,872 in 1996 to $60,942 in 1997
primarily due to the reduction in the Company's outstanding bank debt during
1997. Pro forma interest included interest associated with an EPC note
payable to Aspect of $24,490 and $11,132 for the year ended December 31,
1997 and for the three months ended March 31, 1998, respectively, which was
assumed by the Company and $601,990 and $150,497 associated with borrowings
under the Duke Credit Facility for the year ended December 31, 1997 and the
three months ended March 31, 1998, respectively.
(6) Pro forma general and administrative expenses include historical expense of
EPC in the amount of $1,483,000 and $360,000 for the year ended December 31,
1997 and for the three months ended March 31, 1998, respectively, which the
Company assumed in the Acquisitions.
(7) 1996 included other expense items for the purchase and settlements of
deferred gas contracts. There were no such expenses during 1997.
(8) As adjusted to reflect the receipt by the Company of the estimated net
proceeds from the issuance of the 4.0 million shares of Common Stock offered
hereby and the application of such net proceeds. See "Use of Proceeds" and
"Capitalization."
9
<PAGE>
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Securities Exchange Act
of 1934, as amended (the "Exchange Act"). All statements other than statements
of historical facts included in this Prospectus, including without limitation
statements under "Summary," "Risk Factors," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Business and
Properties" regarding planned capital expenditures, the availability of capital
resources to fund capital expenditures, estimates of proved reserves, the number
of anticipated wells to be drilled in the future, the Company's financial
position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes the
expectations reflected in such forward-looking statements are reasonable, it can
give no assurance such expectations will prove to have been correct. There are
numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the Company's control.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates made by different engineers often vary from one another. In
addition, results of drilling, testing and production after the date of an
estimate may justify revisions of such estimate and such revisions, if
significant, would change the schedule of any further production and development
drilling. Accordingly, reserve estimates generally are different from quantities
of oil and natural gas that ultimately are recovered. Additional important
factors that could cause actual results to differ materially from the Company's
expectations are disclosed elsewhere in this Prospectus. All subsequent written
and oral forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by such factors.
RISK FACTORS
AN INVESTMENT IN THE COMMON STOCK OFFERED HEREBY INVOLVES CERTAIN RISKS.
PROSPECTIVE INVESTORS SHOULD CAREFULLY CONSIDER THE RISK FACTORS SET FORTH
BELOW, AS WELL AS THE OTHER INFORMATION SET FORTH IN THIS PROSPECTUS, BEFORE
MAKING ANY INVESTMENT IN THE COMMON STOCK.
EXPLORATION RISKS; RELIANCE ON CAEX AND 3-D SEISMIC TECHNOLOGY
The Company's principal activity has changed from the acquisition,
production and marketing of natural gas and oil reserves to exploration and
development activities. Exploratory drilling is a speculative activity, and
there can be no assurance as to the success of the Company's drilling program.
The Company's strategy is to enhance the value of its Exploration 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-D displays of subsurface geological formations that enable the Company's
explorationists to detect seismic anomalies and structural features that are not
apparent in 2-D seismic surveys; however, these technologies require greater
pre-drilling expenditures than traditional drilling strategies. Even when fully
used and properly interpreted, 3-D seismic data and visualization techniques
only assist geoscientists in identifying subsurface structures and hydrocarbon
indicators, and do not conclusively allow the interpreter to know if
hydrocarbons will in fact be present in such structures. Exploratory drilling
and, to a lesser extent, development drilling involve a high degree of risk that
no commercial production will be obtained or that the production will be
insufficient to recover drilling and completion costs. The costs of drilling,
completing and operating wells are uncertain. The Company's drilling operations
may be curtailed, delayed or canceled as a result of numerous factors, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. Furthermore, completion of
a well does not assure a profit on the investment or a recovery of drilling,
completion and operating costs. The failure of the Company's current exploration
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activities would have a material adverse effect on the Company's future results
of operations and financial condition. See "Business and Properties--Drilling
Activity."
UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES
This Prospectus contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based upon various
assumptions, including assumptions required by the Securities and Exchange
Commission (the "Commission") as to oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The process of
estimating oil and gas reserves is complex, requiring significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data for each reservoir. As a result, such estimates are inherently
imprecise. Actual future production, oil and gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves may vary substantially from the Company's estimates. Any
significant variance in these assumptions could materially affect the estimated
quantity and value of reserves set forth in this Prospectus. In addition, the
Company's proved reserves may be subject to downward or upward revision based
upon production history, results of future exploration and development,
prevailing oil and gas prices and other factors, many of which are beyond the
Company's control. Actual production, revenues, taxes, development expenditures
and operating expenses with respect to the Company's reserves will likely vary
from the estimates used, and such variances may be material. See "Business and
Properties--Oil and Gas Reserves."
Information concerning the Company's proved reserves contained in this
Prospectus is based on the Company's estimates. The Company has not relied upon
a reserve report from an independent petroleum engineer with respect to such
estimates. Although the Company believes its estimates of its proved reserves
are based on sound judgments and analysis, there can be no assurance that the
Company's estimates will be as accurate as those that might have been prepared
by an independent petroleum engineer. See "Business and Properties--Oil and Gas
Reserves."
Approximately 94% of the Company's total proved reserves at December 31,
1997 were undeveloped, which are by their nature less certain than proved
developed reserves. Recovery of such reserves will require significant capital
expenditures and successful drilling operations. The reserve data set forth in
the Company's estimates assumes that substantial capital expenditures will be
required to develop such reserves. Although cost and reserve estimates
attributable to the Company's oil and gas reserves have been prepared in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated. See "Business and Properties--Oil and Gas
Reserves--Estimated Proved Reserves."
The present value of future net revenues referred to in this Prospectus
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
Commission requirements, the estimated future net cash flows from proved
reserves generally are based on prices and costs as of the date of the estimate,
whereas actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by increases in consumption by gas
purchasers and changes in governmental regulations or taxation. The timing of
actual future net cash flows from proved reserves, and thus their actual present
value, will be affected by the timing of both the production and the incurrence
of expenses in connection with the development and production of oil and gas
properties. In addition, the 10% discount factor, which the Commission requires
to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with the Company
or the oil and gas industry in general. See "Business and Properties--Oil and
Gas Reserves--Estimate of Future Net Revenue from Proved Reserves."
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VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION
The Company's revenue, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
natural gas. The Company's ability to maintain or increase its borrowing
capacity and to obtain additional capital on attractive terms also is
substantially dependent upon oil and gas prices. Prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in
supply and demand, market uncertainty and a variety of additional factors that
are beyond the Company's control. These factors include the level of consumer
product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of oil and gas imports and overall economic conditions. From time to time,
oil and gas prices have been depressed by excess domestic and imported supplies.
There can be no assurance that current price levels will be sustained.
Predicting future oil and natural gas price movements with any certainty is not
possible. Declines in oil and natural gas prices may adversely affect the
Company's financial condition, liquidity and results of operations and may
reduce the amount of the Company's oil and natural gas that can be produced
economically. Market prices for oil have generally declined since December 1997.
Additionally, substantially all of the Company's sales of oil and natural gas
are made in the spot market or pursuant to contracts based on spot market prices
and not pursuant to long-term fixed price contracts. With the objective of
reducing price risk, the Company from time to time enters into hedging
transactions with respect to a portion of its expected future production. There
can be no assurance, however, that such hedging transactions will reduce risk or
mitigate the effect of any substantial or extended decline in oil or natural gas
prices. Any substantial or extended decline in the prices of oil or natural gas
would have a material adverse effect on the Company's financial condition and
results of operations. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Overview."
In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Overview" and "Business and
Properties--Marketing."
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploration projects.
See "Business and Properties--Acquisitions and Divestments."
RISK OF PRICE RISK MANAGEMENT TRANSACTIONS
In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company has in the past and expects to continue to enter
into oil and gas hedging arrangements. These arrangements may include futures
contracts on the New York Mercantile Exchange, fixed price delivery contracts
and financial swaps. These hedging arrangements may apply to only a portion of
the Company's production and provide only partial price protection against a
decline in natural gas prices. While intended to reduce the effects of
volatility of the price of oil and natural gas, such transactions may limit
potential gains by the Company if oil and natural gas prices were to rise
substantially over the price established by the hedge. In addition, such
transactions may expose the Company to the risk of financial loss in certain
circumstances, including instances in which (i) production is less than
expected; (ii) there is a widening of price differentials between delivery
points for the Company's production and the delivery point assumed in the
arrangement; (iii) the counter parties to the Company's future contracts fail to
perform under the
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contracts; or (iv) a sudden, unexpected event has a material impact on oil or
natural gas prices. See "Business and Properties--Hedging Activities and
Marketing."
The Company's only current swap arrangement is the swap arrangement required
by the Company's credit agreement with Bank of America NT&SA (the "Bank Credit
Agreement"). The swap agreement is for 62,500 MMBtu of the Company's monthly
Mid-Continent natural gas production for $1.566 per MMBtu for the period
beginning April 1, 1996 and ending January 31, 1999. The swap was reduced to
31,250 MMBtu on September 25, 1996, in connection with the sale of the N.E.
Cedardale field. The Company recorded a loss of $212,000 on this swap reduction.
The Company's net gas production has been less than the volumes hedged. As of
March 31, 1998, the Company had an accrued liability of $179,947 to recognize
the projected loss from the hedge. The Company has not recently conducted an
active hedging program other than as required by the Bank Credit Agreement. In
that regard, the Company had net losses of $814,029 in 1996, which includes the
$212,000 loss on the swap reductions, and $375,410 in 1997 on its required
hedged positions. See "Business and Properties--Hedging Activities and
Marketing."
HISTORY OF LOSSES; ACCUMULATED AND WORKING CAPITAL DEFICITS
For the years ended December 31, 1996 and 1997, the Company had net losses
of $5,025,019 and $4,953,803. The Company had a net loss of $608,588 for the
three months ended March 31, 1998. The Company's accumulated deficit as of March
31, 1998 was $13,545,450. On a pro forma basis for the year ended December 31,
1997 and the three months ended March 31, 1998, the Company had net losses of
$12,582,956 and $2,386,984, respectively. The Company anticipates that it will
continue to have net losses until it acquires or develops enough additional
producing gas and oil properties to achieve profitability. There can be no
assurance the Company will be able to do so.
ABILITY TO CONTINUE AS A GOING CONCERN
The auditors' report relating to the Company's audited balance sheets as of
December 31, 1997 and 1996 and the related consolidated statements of
operations, stockholders' equity and cash flows for the years then ended
contains an explanatory paragraph as to the Company's ability to continue as a
going concern. Such going concern explanation relates only to the Company's
financial statements covered by the auditors' report. The Company believes that
the consummation of the Acquisitions and the receipt of the net proceeds of this
offering will allow the Company's independent auditors to delete the explanatory
paragraph in their report with respect to the Company's next audited financial
statements, but there can be no assurance in that regard. See "Independent
Auditors' Report" and Note 2 to Financial Statements.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made and intends to make substantial capital expenditures in
connection with the exploration and development of its gas and oil properties.
Historically, the Company has funded its capital expenditures through a
combination of internally generated funds, equity and long-term debt financing,
and short-term financing arrangements. Based on its current operations, the
Company anticipates that its capital expenditures through the end of 1998 will
be funded from (i) proceeds from the sale of the Common Stock offered hereby;
(ii) the availability of credit under the Company's Bank Credit Agreement and
other credit facilities; (iii) sales of promoted interests in the Exploration
Projects to industry partners; and (iv) if the foregoing financing sources are
inadequate, the sale of interests in the Company's assets to unaffiliated third
parties. The availability of credit under the Bank Credit Agreement is subject
to several variables, such as the level of production from existing wells,
prices of gas and oil and the Company's success in locating and producing new
reserves. The Company currently is attempting to renegotiate certain of the
terms of the Bank Credit Agreement to increase the borrowing capacity
thereunder, however, there can be no assurance that the Company will be
successful in doing so. The Company has a capital expenditure budget of $25.0
million for the 12 months following the date of this Prospectus. The proceeds of
this Offering and the borrowing capacity currently available under the Bank
Credit Agreement
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will not be sufficient to fund such budget in full. Therefore, unless the
Company finds additional sources of capital or negotiates an amendment to the
Bank Credit Agreement to create increased borrowing capacity, the Company will
be required to seek additional sources of capital to fund its capital
expenditure budget, sell interests in its Exploration Projects, or curtail its
drilling program. There can be no assurance that funds available to the Company
will be sufficient for the Company to carry out its proposed plans. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
MORTGAGED GAS AND OIL PROPERTIES; CREDIT AGREEMENT COVENANTS AND RESTRICTIONS
The Company has granted to Bank of America NT&SA a mortgage on substantially
all of the Company's proved developed gas and oil properties to secure repayment
under the Bank Credit Agreement. In addition, the Company granted a mortgage to
Duke Energy Financial Services, Inc. on substantially all of the assets acquired
in the Acquisitions to secure repayment under the Duke Credit Facility, however,
indebtedness under the Duke Credit Facility will be repaid with a portion of the
proceeds from this Offering, and upon such repayment, the mortgage will be
released. The party providing financing for the Starboard Project (the
"Starboard Project Financing") has been granted an overriding royalty interest
in the Starboard Project properties. Repayment of amounts owed are payable only
from the proceeds of the overriding royalty interest, but such payments are
secured by a mortgage on the Starboard Project properties. These liens limit the
Company's ability to borrow additional funds. The amount of borrowings under the
Bank Credit Agreement is based on the maintenance of adequate natural gas and
oil reserves to support the amount borrowed. Should the estimated proved natural
gas and oil reserves or the price to be received for these reserves decline
below the required reserve value, the Company would be required either to
accelerate payment, repay a specified amount of the borrowings so as to have
adequate reserve value to support the borrowing, or provide additional
collateral for the loan. A failure by the Company to comply with the covenants
and restrictions contained in the Bank Credit Agreement, or obtain a waiver to
such covenants and restrictions, will constitute a default under the terms of
the Bank Credit Agreement and the Starboard Project Financing, resulting in the
indebtedness under both of those credit arrangements becoming immediately due
and payable and enabling the lenders to foreclose against the collateral for the
loans. The Company historically has not been, and currently is not, in
compliance with all its covenants under the Bank Credit Agreement, but has
secured waivers of default for past noncompliance. The Company expects, but
cannot assume, that waivers will continue to be granted in the future. Moreover,
the Company believes that upon consummation of this Offering, the Company will
be in compliance with all of the covenants of the Bank Credit Agreement. The
Company believes, but cannot assure, it will be able to continue to make the
payments required by the Bank Credit Agreement. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources."
RESERVE REPLACEMENT
As is customary in the oil and gas exploration and production industry, the
Company's future success depends upon its ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless the
Company replaces its estimated proved reserves (through development, exploration
or acquisition), the Company's proved reserves generally will decline as they
are produced.
The Company's current strategy includes increasing its reserve base through
acquisitions of leaseholds with drilling potential and by continuing to exploit
its existing properties. There can be no assurance, however, that the Company's
exploration and development projects will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at economically viable costs. Furthermore, while the Company's revenues
may increase if prevailing oil and gas prices increase significantly, the
Company's finding costs for additional reserves could also increase. For a
discussion of the Company's reserves, see "Business and Properties--Oil and Gas
Reserves."
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OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's control. These risks include the
risk that no commercially productive oil or natural gas reservoirs will be
encountered, that operations may be curtailed, delayed or canceled and that
title problems, compliance with governmental requirements, mechanical
difficulties or shortages or delays in the delivery of drilling rigs and other
equipment may limit the Company's ability to market its production. There can be
no assurance that new wells drilled by the Company will be productive or that
the Company will recover all or any portion of its investment. Drilling for oil
and natural gas may involve unprofitable efforts, not only from dry wells but
also from wells that are productive but do not produce sufficient net revenues
to return a profit after drilling, operating and other costs. In addition, the
Company's properties may be susceptible to hydrocarbon drainage from production
by other operators on adjacent properties.
Industry operating risks include 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, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, many of the Company's oil and gas operations are located in an
area that is subject to tropical weather disturbances, some of which can be
severe enough to cause substantial damage to facilities and possibly interrupt
production. In accordance with customary industry practice, the Company
maintains insurance against some, but not all, of the risks described above.
There can be no assurance that any insurance will be adequate to cover losses or
liabilities. The Company cannot predict the continued availability of insurance
at premium levels that justify its purchase. Losses and liabilities arising from
uninsured or under-insured events could have a material adverse effect on the
financial condition and results of operations of the Company.
From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which the Company owns an interest
may be subject to production curtailments. The curtailments may vary from a few
days to several months. In most cases the Company will be provided only limited
notice as to when production will be curtailed and the duration of such
curtailments. The Company is currently not curtailed on any of its production.
See "Business and Properties--Operating Hazards and Insurance."
CONTROL BY PRINCIPAL SHAREHOLDERS.
As a result of the Acquisitions, EPC owns approximately 44% and Aspect owns
approximately 36.27% of the Company's issued and outstanding Common Stock. As a
result, each of EPC and Aspect are in a position to substantially influence the
outcome of shareholder votes on the election of directors and other matters.
Moreover, EPC and Aspect together have sufficient voting power to control the
approval of any matter brought before the Company's shareholders. EPC and Aspect
have not entered into any agreement with respect to the voting of their Common
Stock. In addition, if EPC or Aspect were to sell a significant number of their
shares of Common Stock in the public market, the prevailing market price of the
Common Stock could be adversely affected. See "--Shares Eligible for Future
Sale."
MINORITY OWNERSHIP OF OIL AND GAS INTERESTS.
The Company owns a minority interest in some of the Exploration Projects.
Operational decisions, such as the selection of drill sites, when to drill
wells, the amount to be expended on any well, determining whether to conduct
recompletion or other activities, and similar matters will be made by the
operators of the wells on each Exploration Project. The interests of the
operators of the wells and of the majority working interest owners in many cases
may not be aligned with the Company's interests. Therefore, the Company may be
unable to control many important aspects of the operation and development of
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Exploration Projects on which it owns a minority interest, and the development
of those Exploration Projects may be conducted in a fashion that is adverse to
the Company's best interests. See "Business and Properties--Exploration
Projects."
UNCERTAINTY AS TO ESTIMATES OF FAIR MARKET VALUES
The Company engaged Cornerstone to deliver a written opinion to the
Company's Board of Directors (the "Cornerstone Opinion") to estimate the fair
market value of the assets acquired in the Acquisitions. The Cornerstone Opinion
estimates such fair market value to be approximately $54.2 million as of January
23, 1998. Cornerstone's estimate of the fair market value of the assets acquired
in the Acquisitions was based upon a variety of factors including (i) an
analysis of the risk adjusted reserves (derived from a comprehensive
assessment), (ii) estimated replacement costs that a buyer would incur to bring
individual projects or properties to their current state of development, (iii)
current industry factors such as supply and demand for oil and gas, commodity
prices and availability of seismic and drilling equipment and (iv) oil and gas
prices on the date of the Cornerstone Opinion. For the analysis of risk adjusted
reserves, Cornerstone received Company-provided data and made adjustments
Cornerstone deemed appropriate to reflect what it felt would reasonably be
categorized as possible reserves in accordance with the definition of the
Society of Petroleum Engineers. Prices for oil and gas generally have declined
since such date. There can be no assurance that Cornerstone's estimate of the
fair market value of such assets would be as high as that contained in the
Cornerstone Opinion if Cornerstone relied on current oil and gas prices in
reaching its opinion. Cornerstone's estimates of the fair market values of the
assets do not purport to be appraisals or necessarily reflect the prices at
which such assets could actually be sold. Because such estimates are inherently
subject to uncertainty and based upon numerous factors or events beyond the
control of the parties to the Acquisition Agreement or their respective
advisors, no assurances can be given that such estimates will prove to be
accurate. See "Business and Properties--General."
GOVERNMENTAL REGULATION
Oil and gas operations are subject to various United States federal, state
and local governmental laws and regulations that change from time to time in
response to economic or political conditions. Matters subject to regulation
include discharge permits for drilling operations, drilling and abandonment
bonds, reports concerning operations, the spacing of wells, and unitization and
pooling of properties, environmental protection, and taxation. From time to
time, regulatory agencies have imposed price controls and limitations on
production by restricting the rate of flow of oil and gas wells below actual
production capacity in order to conserve supplies of oil and gas. In addition,
the production, handling, storage, transportation and disposal of oil and gas,
by-products thereof and other substances and materials produced or used in
connection with oil and gas operations are subject to regulation under laws and
regulations primarily relating to protection of human health and the
environment. Failure to comply with these laws and regulations may result in the
assessment of administrative, civil, and criminal penalties, as well as
injunctive relief. The Company also may be subject to substantial clean-up costs
for any toxic or hazardous substance that may exist under any of its current
properties or properties that it has owned or operated in the past. To date,
expenditures related to complying with these laws and regulations and for
remediation of existing environmental contamination have not been significant in
relation to the Company's results of operations.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation. In addition,
the recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. For instance, legislation has been proposed in
Congress from time to time that would reclassify certain crude oil and natural
gas exploration and production wastes as "hazardous wastes" which would make the
reclassified wastes subject to much more stringent handling, disposal and
clean-up requirements. If such legislation were to be enacted, it could have a
significant impact on the Company's
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operating costs, as well as the oil and gas industry in general. The Company
could incur substantial costs to comply with environmental laws and regulations,
and the Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its production. See "Business and Properties--
Regulation."
TITLE DEFECTS
Title to the Company's oil and gas leases, including those purchased in the
Acquisitions, will not be examined until drill sites are selected. 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. Although title will be examined before
drilling on a site commences, as is customary in the industry, the Company does
not intend to purchase title insurance, and there can be no assurance that
losses relating to any lease will not result from title defects, defects in the
assignment of leasehold rights or prior encumbrances. See "Business and
Properties--Title to Properties."
COMPETITION FOR GAS AND OIL LEASES AND SEISMIC PERMITS
Substantial competition exists for gas and oil leases and there can be no
assurance the Company will be able to acquire the gas and oil leases it seeks.
Similar competition exists for seismic permits without which 2-D and 3-D seismic
surveys cannot be conducted. There can be no assurance the Company can obtain
the permits necessary to conduct seismic surveys it may desire to conduct. The
seismic permitting risk can be greater in the State of Louisiana, where current
law requires permits from owners of at least an undivided 80% interest in each
tract over which a seismic survey is proposed to be conducted. See "Business and
Properties--Competition."
CONFLICTS OF INTEREST
Michael E. Johnson and Charles J. Smith each own 50% of EPC's common stock
and Alex M. Cranberg owns a controlling interest in Aspect. Their respective
relationships with EPC and Aspect create conflicts of interest with their
serving as directors of the Company. Aspect has retained a substantial interest
in many of the projects that Aspect transferred to the Company pursuant to the
Acquisition Agreement, and Aspect has the right to acquire oil and gas interests
in areas adjacent to those covered by the Exploration Projects. Aspect's
participation in these additional exploration projects creates a conflict of
interest with the Company. The Acquisition Agreement provides, however, that
Aspect will not participate in any exploration project in the areas of mutual
interest created pursuant to the Acquisition Agreement. In addition, Aspect and
the Company have entered into an agreement that for a period of three years
beginning May 19, 1998, before selling any projects that Aspect owns now or may
own during such three year period in certain defined counties surrounding the
Exploration Projects, Aspect will first offer to sell such project to the
Company at a price and on terms identical to those initially offered to third
party purchasers. Nonetheless, Aspect will continue to participate in oil and
gas exploration activities outside the areas established by the Acquisition
Agreement and the areas adjacent thereto. Aspect is not obligated to offer the
Company a participation in those projects, and Aspect will be in competition
with the Company to that extent. See "Business and Properties--Conflicts of
Interest."
BROAD DISCRETION IN USE OF PROCEEDS
The board of directors has broad discretion to allocate the proceeds of the
Offering. The Company plans to use $7.8 million, or 54.8%, of the net proceeds
of the Offering for the repayment of debt and $6.4 million, or 45.2%, of the net
proceeds of the Offering for exploration and development activities. The actual
allocation of funds, however, will depend on the Company's success in exploring
for, finding and developing gas and oil reserves. If results do not meet the
Company's requirements due to unanticipated expenses, lack of success or
otherwise, it may reallocate the proceeds among other current exploration and
development projects or pursue different exploration and development activities,
or seek to acquire
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additional natural gas or oil assets. If the Company uses a portion of the net
proceeds of the Offering to acquire or lease additional natural gas or oil
assets or other interests in prospects, the Company will not be required under
Delaware law to seek stockholder approval of such transactions. See "Use of
Proceeds."
COMPETITION
The Company operates in a highly competitive environment. The Company
competes with major integrated and independent gas and oil companies for the
acquisition of desirable gas and oil properties and leases, for the equipment
and labor required to develop and operate such properties, and in the marketing
of natural gas to end-users. Many of these competitors have financial and other
resources substantially greater than those of the Company. In addition, many of
the Company's larger competitors may be better able to respond to factors that
affect the demand for oil and natural gas production, such as changes in
worldwide oil and natural gas prices and levels of production, the cost and
availability of alternative fuels and the application of government regulations.
The Company also competes in attracting and retaining technical personnel,
including geologists, geophysicists and other specialists. Although the Company
believes the technical staff EPC provided after consummation of the Acquisitions
enhances the Company's professional staff, there can be no assurance the Company
will be able to attract or retain technical personnel in the future. See
"Business and Properties--Competition."
DIVIDEND POLICY--COMMON STOCK
The Company does not currently pay cash dividends on its Common Stock and
does not anticipate paying dividends in the near future. The Company is
restricted under the terms of the Bank Credit Agreement from making
distributions of any type with respect to any class of its capital stock unless
it meets certain financial requirements (the "Restricted Payment Tests"),
including the maintenance of a current ratio of not less than 1.1:1 and
maintenance of tangible net worth in excess of $5,000,000, after giving effect
to the proposed distribution. The Company currently does not meet all of the
Restricted Payment Tests and, unless it receives a waiver from such tests, is
restricted under the terms of the Bank Credit Agreement from making any dividend
payments or other distribution with respect to any class of its capital stock.
The Company believes that upon consummation of this Offering, the Company will
be in compliance with the Restricted Payment Tests. See "Dividend Policy."
DEPENDENCE ON KEY PERSONNEL
The Company's business is dependent upon the performance of certain of its
executive officers. The Company has not entered into employment agreements with
these executive officers. There can be no assurance the Company will be able to
enter into any such employment agreements or otherwise to retain such officers.
The Company does not maintain key-man life insurance on any of its employees.
See "Management--Directors and Executive Officers."
SHARES ELIGIBLE FOR FUTURE SALE
As of May 15, 1998, the Company had a total of 11,762,687 shares of Common
Stock outstanding after giving effect to the Reverse Split and the Acquisitions.
Of these shares, 1,429,990 shares are freely transferable by persons other than
affiliates, as defined in regulations under the Securities Act, without
restriction or further registration under the Securities Act. An additional
225,985 shares of Common Stock outstanding are "Restricted Securities" within
the meaning of Rule 144 under the Securities Act and may not be sold in the
absence of registration under the Securities Act, unless an exemption from
registration is available, including the exemption provided by Rule 144. Under
Rule 144 as currently in effect, all such shares are currently eligible for
sale, subject to certain volume limitations and restrictions on the manner of
sale.
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The Company issued 10,106,702 shares of Common Stock to EPC, Aspect, an
affiliate of Enron Corp. and certain of Aspect's employees as consideration for
the assets acquired in the Acquisitions and certain overriding royalty interests
relating thereto. Such shares, which constitute 85.92% of all of the issued and
outstanding Common Stock, are Restricted Securities; however, the Company has
filed a registration statement with respect to the Common Stock issued in the
Acquisitions, and the Commission has declared such registration statement
effective under the Securities Act. In addition, certain affiliates of the
Company are purchasing an aggregate of 350,000 shares of Common Stock in this
Offering, all of which will be freely tradable. Although EPC, Aspect and such
Enron Corp. affiliate may resell the Common Stock issued to them pursuant to the
Acquisition Agreement pursuant to such registration statement, EPC and Aspect
have indicated they have no present intention to do so. In addition, EPC, Aspect
and the affiliates of the Company who are purchasing shares of Common Stock in
this Offering have entered into written agreements with the Representative that
they will not sell any of their Common Stock until the expiration of 180 days
after the date of this Prospectus, and such Enron Corp. affiliate has entered
into a written agreement with the Representative that it will not sell any of
its Common Stock until the expiration of 90 days after the date of this
Prospectus.
Approximately 1,767,750 shares of Common Stock are issuable upon the
exercise of existing options and warrants. Of such shares, 50,000 are issuable
upon exercise of warrants with an exercise price of $3.00 per share issued to
EPC, Aspect and an affiliate of the Representative in connection with the Duke
Credit Facility and in connection with a previous credit facility the Company
entered into with an affiliate of Aspect, and repayment of indebtedness of which
was guaranteed by EPC and an affiliate of the Representative (the "Initial
Bridge Facility"). In addition (i) 291,667 shares are issuable upon exercise of
the Company's Series A Warrants at an exercise price of $36.00 per share; (ii)
776,250 shares are issuable upon exercise of the Company's Series B Warrants at
an exercise price of $12.15 per share; (iii) 193,334 shares are issuable upon
exercise of warrants issued to the underwriters in connection with certain of
the Company's previous equity offerings at exercise prices ranging from $12.15
per share to $34.50 per share; (iv) 210,000 shares are issuable upon exercise of
the Representative's Warrant at an exercise price of $7.20 per share, and (v)
246,500 shares are issuable upon the exercise of additional outstanding options
and warrants with exercise prices ranging from $3.78 to $24.00 per share. All of
such shares have been or may be registered for resale pursuant to registration
rights agreements.
The sale of a material number of the shares of Common Stock eligible for
resale without restriction in the public markets or that will be eligible for
resale without restriction upon registration pursuant to applicable registration
rights agreements could have a material adverse effect on the trading price of
the Company's Common Stock.
YEAR 2000 COMPLIANCE
The Company has recognized the need to ensure its systems, equipment and
operations will not be adversely impacted by the change to the calendar year
2000. As such, the Company operates on an internally designed software package
that is compliant with the year 2000. The Company is attempting to identify
other potential areas of risk and has begun addressing these in its planning,
purchasing and daily operations. The total costs of connecting all internal
systems, equipment and operations to the year 2000 has not been fully
quantified, but it is not expected to be a material cost to the Company.
However, no estimates can be made as to the potential adverse impact resulting
from the failure of third party service providers and vendors to prepare for the
year 2000. If any interruptions occur, they may have a material adverse effect
on the Company's business, financial condition and results of operations.
Furthermore, there can be no assurance that the Company's customers and
suppliers are or will be year 2000 compliant. The failure of the Company's
customers and suppliers to achieve year 2000 compliance could have a material
adverse effect on the Company's business, financial condition and results of
operations. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Year 2000."
19
<PAGE>
DISCRETIONARY ISSUANCE; ANTI-TAKEOVER PROVISIONS
The Company's Certificate of Incorporation (the "Certificate of
Incorporation") authorizes the issuance of preferred stock with such
designations, rights and preferences as may be determined from time to time by
the Board of Directors. Accordingly, the Board of Directors is empowered,
without shareholder approval, to issue preferred stock with dividend,
liquidation, conversion, voting or other rights that could adversely affect the
voting power or other rights of holders of the Common Stock. In the event of
issuance, the preferred stock could be used, under certain circumstances, as a
method of discouraging, delaying or preventing a change in control of the
Company, which could have the effect of discouraging bids for the Company and,
thereby, prevent shareholders from receiving the maximum value for their shares.
Although the Company has no present intention to issue any preferred stock,
there can be no assurance the Company will not do so in the future.
In addition to the provision for the issuance of preferred stock, the
Company's Certificate of Incorporation and Bylaws include several other
provisions that may have the effect of inhibiting a change of control of the
Company. These include a classified Board of Directors, no shareholder action by
written consent and advance notice requirements for shareholder proposals and
director nominations. These provisions may discourage a party from making a
tender offer for or otherwise attempting to obtain control of the Company.
Moreover, as a Delaware corporation, the Company is subject to the provisions of
the Delaware General Corporation Law (the "DGCL") that could make it difficult
or tend to discourage attempts to acquire the Company. The DGCL includes
provisions that are intended to encourage persons considering unsolicited tender
offers or other unilateral takeover proposals to negotiate with the Company's
Board of Directors rather than pursue non-negotiated takeover attempts. See
"Description of Securities--Provisions Affecting Control of the Company."
LIMITED LIABILITY OF DIRECTORS; INDEMNIFICATION OF DIRECTORS AND OFFICERS
The Company's Certificate of Incorporation, as permitted by the DGCL,
eliminates in some circumstances the monetary liability of the Company's
directors for breach of their fiduciary duty as directors. In those
circumstances the Company's directors will not be liable to the Company or its
shareholders for breach of such duty. The Company's Certificate of Incorporation
also provides that the Company shall indemnify its directors and officers to the
full extent permitted by the DGCL.
20
<PAGE>
USE OF PROCEEDS
The net proceeds to the Company from the sale of the shares of Common Stock
offered hereby are approximately $14.2 million ($16.5 million if the
Underwriters' over-allotment option is exercised in full), after deducting
Underwriters' discounts and commissions, the Representative's nonaccountable
expense allowance of $300,000 and additional estimated expenses of the Offering
of $350,000 payable by the Company.
Of such net proceeds, the Company intends to use $7.8 million to repay
indebtedness under the Duke Credit Facility and the remainder for exploration
activities on the Exploration Projects. As of the date hereof, a total of
approximately $11.0 million of costs for exploration activities have been
incurred. Therefore, the net proceeds of this Offering will be insufficient to
pay all of the costs the Company has incurred on exploration activities through
the date hereof.
The following table illustrates the Company's intended use of the net
proceeds of this Offering and the percentage of such net proceeds represented by
each purpose:
<TABLE>
<CAPTION>
APPROXIMATE PERCENT OF
USE OF PROCEEDS DOLLAR AMOUNT NET PROCEEDS
- ---------------------------------------------------------------- -------------- -------------
<S> <C> <C>
Exploration activities(1)....................................... $ 6,430,000 45.2%
Repayment of debt............................................... 7,800,000 54.8%
-------------- -----
Total......................................................... $ 14,230,000 100.0%
-------------- -----
-------------- -----
</TABLE>
- ------------------------
(1) Includes payment of approximately $4.75 million of the aggregate $7.55
million of costs incurred by Aspect and EPC before the closing of the
Acquisitions and approximately $6.25 million in additional exploration costs
incurred as of the date hereof.
Borrowings under the Duke Credit Facility bear interest at the prime rate
plus 4.0% (12.5% as of the date hereof). All amounts outstanding under the Duke
Credit Facility mature no later than July 31, 1999. Proceeds from the Duke
Credit Facility were used to repay borrowings under the Initial Bridge Facility,
which was a $1.8 million credit facility that an affiliate of Aspect provided to
the Company to fund operational and exploration requirements before the closing
of the Acquisitions. Aggregate borrowings of $500,000, plus interest, under the
Initial Bridge Facility were repaid in full with the proceeds of the Duke Credit
Facility.
The Company anticipates, based on currently proposed plans and assumptions
relating to its operations, that the proceeds from this Offering, together with
projected cash flow from operations, the borrowing capacity available under the
Bank Credit Agreement and other sources, will be sufficient to satisfy its
contemplated capital and operating cash requirements through fiscal 1998,
however, such Offering proceeds and borrowing capacity under the Bank Credit
Agreement are not anticipated to be sufficient to fund the Company's capital
expenditure budget for the 12 months following the date hereof. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operation--Liquidity and Capital Resources." If cash flows do not develop as
anticipated, funds are not available under the Bank Credit Agreement or if the
Company's proposed plans or the basis for its assumptions change, the Company
may be required to obtain additional sources of capital or curtail its
exploration activities. Moreover, additional funds available under the Bank
Credit Agreement may not be available if the Company's then existing natural gas
and oil reserves are not sufficient to secure the additional borrowings. The
Company has used most of its existing assets to secure the Bank Credit
Agreement, the Starboard Project Financing and the Duke Credit Facility, and
there can be no assurance additional assets will be available to secure
additional borrowings.
The Company plans to use a substantial amount of the proceeds from this
Offering for exploration and development activities. The actual allocation of
funds, however, will depend on the Company's success
21
<PAGE>
in exploring for, finding and developing gas and oil reserves. If results do not
meet the Company's requirements (due to unanticipated expenses, lack of success
or otherwise), the board of directors may reallocate the proceeds among other
current exploration and development projects or pursue different exploration and
development activities, or seek to acquire additional natural gas or oil assets.
See "Risk Factors--Broad Discretion in Use of Proceeds." The Company may use a
portion of the proceeds to acquire or lease other interests in prospects. Any
decision to make an acquisition will be dependent on consideration of a variety
of factors, including business prospects, purchase price and financial terms of
the transaction. The Company has no agreements, understandings or arrangements
with respect to any acquisition. Pending application of the net proceeds
described above, the Company will invest such net proceeds in short term
investment grade interest bearing securities.
DIVIDEND POLICY
To date, the Company has not paid any dividends on its Common Stock. The
payment of dividends, if any, in the future is within the discretion of the
Board of Directors and will depend on the Company's earnings, its capital
requirements and financial condition and other relevant factors. The Company
does not expect to declare or pay any dividends on Common Stock in the
foreseeable future. The Company also is restricted under the terms of the Bank
Credit Agreement from making distributions of any type with respect to any class
of its capital stock unless it meets the Restricted Payment Tests provisions of
the Bank Credit Agreement, including the maintenance of a current ratio of not
less than 1.1:1 and maintenance of tangible net worth in excess of $5,000,000,
after giving effect to the proposed distribution. The Company currently does not
meet all of the Restricted Payment Tests and, accordingly, is restricted under
the terms of the Bank Credit Agreement from making any dividend payments or
other distribution with respect to any class of its capital stock.
PRICE RANGE OF COMMON STOCK
The Common Stock is traded on the Nasdaq Small-Cap Market under the symbol
"ESNJ." On July 15, 1998, the closing price of the Common Stock as reported by
the Nasdaq Small-Cap Market was $4.125.
The following table sets forth, for the periods indicated, the high and low
sales prices of the Common Stock as reported on the Nasdaq Small-Cap Market
after giving effect to the Reverse Split, assuming that such high and low sales
prices after giving effect to the Reverse Split are six times the pre-Reverse
Split prices.
<TABLE>
<CAPTION>
HIGH LOW
--------- ---------
<S> <C> <C>
YEAR ENDED DECEMBER 31, 1996:
First Quarter............................................................................. $ 16.125 $ 8.532
Second Quarter............................................................................ $ 16.125 $ 11.250
Third Quarter............................................................................. $ 16.500 $ 9.750
Fourth Quarter............................................................................ $ 17.625 $ 12.00
YEAR ENDED DECEMBER 31, 1997:
First Quarter............................................................................. $ 21.375 $ 12.375
Second Quarter............................................................................ $ 14.250 $ 10.125
Third Quarter............................................................................. $ 12.00 $ 3.75
Fourth Quarter............................................................................ $ 12.00 $ 4.125
YEAR ENDED DECEMBER 31, 1998:
First Quarter............................................................................. $ 7.125 $ 4.125
Second Quarter............................................................................ $ 6.375 $ 4.00
Third Quarter through July 15, 1998....................................................... $ 4.375 $ 4.125
</TABLE>
On July 15, 1998, there were approximately 94 common shareholders of record
and 2,670 beneficial owners of the Common Stock.
The Common Stock will be listed on notice of issuance on the Boston Stock
Exchange.
22
<PAGE>
CAPITALIZATION
The following table sets forth (i) the capitalization of the Company at
March 31, 1998; (ii) the pro forma capitalization of the Company at March 31,
1998 after giving effect to the Acquisitions, the redemption of the Preferred
Stock and the receipt and application of the proceeds from the Duke Credit
Facility; and (iii) the pro forma capitalization of the Company as adjusted to
give effect to the sale of the 4.0 million shares of Common Stock offered hereby
and the application of the net proceeds therefrom as described under "Use of
Proceeds." This table should be read in conjunction with the financial
statements and related notes of the Company appearing elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
----------------------------------------------
PRO FORMA
HISTORICAL PRO FORMA AS ADJUSTED
-------------- -------------- --------------
<S> <C> <C> <C>
Long-term debt, excluding current maturities, net of
unamortized discount of $44,224 (1)............................ $ 2,893,055 $ 4,607,785 $ 1,059,723
Stockholders' equity:
Convertible Preferred Stock; $.01 par
value, 5,000,000 shares authorized; 85,961
issued and outstanding (0 shares outstanding
on a pro forma basis)........................................ 860 -- --
Common Stock; $.01 par value,
40,000,000 shares authorized; 1,655,984 shares issued and
outstanding; 11,812,684 shares pro forma and 15,812,684
shares pro forma as adjusted (2)............................. 16,560 118,127 158,127
Unamortized value of warrants issued (3)....................... (20,371) (20,371) (20,371)
Additional paid-in capital..................................... 14,751,425 66,876,830 80,725,465
Retained earnings (deficit).................................... (13,545,450) (13,545,450) (13,545,450)
-------------- -------------- --------------
Total stockholders' equity................................... 1,203,024 53,429,136 67,317,771
-------------- -------------- --------------
Total capitalization....................................... $ 4,096,079 $ 58,036,921 $ 68,377,494
-------------- -------------- --------------
-------------- -------------- --------------
</TABLE>
- ------------------------
(1) In addition to the amount of pro forma as adjusted long-term debt shown as
being repaid from the proceeds of the Offering, the Company intends to repay
amounts borrowed after March 31, 1998 that are not reflected in the table.
(2) Includes 50,000 shares of Common Stock issuable upon the exercise of
in-the-money warrants held by Aspect, EPC and an affiliate of the
Representative, which warrants are assumed to have been exercised; does not
include 1,717,750 shares of Common Stock issuable upon the exercise of
additional outstanding warrants and options. See "Summary--The Offering" and
"Underwriting."
(3) Common shares subscribed in 1993 but unpaid.
23
<PAGE>
PRO FORMA FINANCIAL STATEMENTS
The historical financial information for the year ended December 31, 1997
are derived from the Company's audited financial statements. The pro forma
consolidated statement of operations information for the year ended December 31,
1997 and for the three months ended March 31, 1998 combine the Company's
historical information as adjusted to give effect to the Acquisitions, the
redemption of the Preferred Stock and the use of proceeds from the Duke Credit
Facility as if they had occurred on January 1, 1997. The pro forma balance sheet
information as of March 31, 1998 is presented as if the Acquisitions had been
consummated on that date. The pro forma statements of operations and balance
sheet are provided for comparative purposes only and should be read in
conjunction with the Company's historical consolidated financial statements
included elsewhere in this Prospectus. The pro forma information presented is
not necessarily indicative of the combined financial results as they may be in
the future or as they might have been for the periods indicated had the
Acquisitions been consummated as of January 1, 1997 and March 31, 1998.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
---------------------------------------------------------------
COMPANY PRO FORMA REFINANCING
HISTORICAL ADJUSTMENTS TRANSACTION PRO FORMA
----------- ----------------- ----------- ------------
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
Revenues:
Gas and oil revenues...................................... $ 664,126 $ 664,126
Realized gain (loss) on commodity transaction............. (375,410) (375,410)
Gain (loss) on sale of assets............................. 452,020 452,020
Unrealized loss on commodity transactions................. (128,936) (128,936)
Operating fees............................................ 55,021 55,021
Other revenues............................................ 241,788 241,788
----------- ----------------- ----------- ------------
Total revenues.......................................... 908,609 908,609
----------- ----------------- ----------- ------------
Cost and expenses:
Lease operating expense................................... 427,240 427,240
Production taxes.......................................... 24,497 24,497
Transportation and gathering costs........................ 143,265 143,265
Depletion, depreciation and
amortization............................................ 315,880 315,880
Impairment of oil and gas properties...................... 349,384 349,384
Exploration costs......................................... 2,258,702 $5,519,673(a) 7,778,375
Delay rentals............................................. 211,690 211,690
Interest expense.......................................... 60,942 626,480(b)(f) 687,422
General and administrative................................ 2,070,812 1,483,000(e) 3,553,812
----------- ----------------- ----------- ------------
Total costs and expenses................................ 5,862,412 7,629,153 13,491,565
----------- ----------------- ----------- ------------
Net loss.................................................... (4,953,803) (7,629,153) (12,582,956)
----------- ----------------- ----------- ------------
Cumulative preferred stock dividend......................... 103,153 $(103,153)(d) --
----------- ----------------- ----------- ------------
Net loss available for common stockholders................ $(5,056,956) $(7,629,153) $ 103,153 $(12,582,956)
----------- ----------------- ----------- ------------
----------- ----------------- ----------- ------------
Net loss per common share................................. $ (3.07) $ (1.07)
----------- ------------
----------- ------------
Weighted average number of common shares outstanding........ 1,646,311 11,803,011
</TABLE>
24
<PAGE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 1998
---------------------------------------------------------------
COMPANY REFINANCING
HISTORICAL PRO FORMA ADJUSTMENTS TRANSACTION PRO FORMA
------------ --------------------- ----------- -------------
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
Revenues:
Gas and oil revenues.......................... $ 48,503 $ 48,503
Realized gain (loss) on commodity
transaction................................. (47,875) (47,875)
Gain (loss) on sale of assets................. 2,875 2,875
Unrealized loss on commodity transactions..... (51,011) (51,011)
Operating fees................................ 6,992 6,992
Other revenues................................ 23,930 23,930
------------ ----------- ----------- -------------
Total revenues.............................. (16,586) (16,586)
------------ ----------- ----------- -------------
Cost and expenses:
Lease operating expense....................... 69,773 69,773
Production taxes.............................. (1,090) (1,090)
Transportation and gathering costs............ 639 639
Depletion, depreciation and amortization...... 53,568 53,568
Exploration costs............................. 3,560 $ 1,256,767(a) 1,260,327
Delay rentals................................. (12,685) (12,685)
Interest expense.............................. 19,223 161,629 (b)(f 180,852
General and administrative.................... 459,014 360,000(e) 819,014
------------ ----------- ----------- -------------
Total costs and expenses.................... 592,002 1,778,396 2,370,398
------------ ----------- ----------- -------------
Net loss........................................ (608,588) (1,778,396) $ (2,386,984)
------------ ----------- ----------- -------------
Cumulative preferred stock dividend............. 25,788 (25,788 (d) --
------------ ----------- ----------- -------------
Net loss available for common stock........... $ (634,376) $ (1,778,396) $ 25,788 $ (2,386,984)
------------ ----------- ----------- -------------
------------ ----------- ----------- -------------
Net loss per common share..................... $ (0.38) $ (0.20)
------------ -------------
------------ -------------
Weighted average number of common shares
outstanding................................... 1,655,984 11,812,684
</TABLE>
25
<PAGE>
<TABLE>
<CAPTION>
AS OF MARCH 31, 1998
----------------------------------------------------------------------------------
COMBINED
COMPANY ENTITIES PRO FORMA REFINANCING
HISTORICAL HISTORICAL ADJUSTMENTS TRANSACTION PRO FORMA
------------ -------------- -------------------- -------------- -----------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET:
ASSETS
Current Assets:
Cash and cash equivalents.................. $ 188,495 $ 150,000(c) $ 338,495
Accounts receivable, net of allowance for
doubtful accounts of $7,915.............. 176,507 176,507
Prepaid and other expenses................. 141,074 141,074
Current portion of notes receivable from
EPC...................................... 466,664 $ (466,664)(h) --
Receivables from affiliates................ 97,765 $ 564,338(f) 662,103
------------ -------------- -------------------- -------------- -----------
Total current assets................... 1,070,505 564,338 150,000 (466,664) 1,318,179
Property and equipment:
Oil and gas properties....................... 3,635,538 19,866,800(g) 34,333,200(g) 3,000,000(b) 60,835,538
Other property and equipment................. 1,151,592 1,151,592
------------ -------------- -------------------- -------------- -----------
4,787,130 19,866,800 34,333,200 3,000,000 61,987,130
Less accumulated DD&A...................... (1,295,435) (1,295,435)
------------ -------------- -------------------- -------------- -----------
Property and equipment, net.............. 3,491,695 19,866,800 34,333,200 3,000,000 60,691,695
Other assets................................. 513,856 513,856
Notes receivable from EPC.................... 1,283,336 (1,283,336)(h) --
------------ -------------- -------------------- -------------- -----------
Total other assets..................... 1,797,192 (1,283,336) 513,856
Total assets........................... $ 6,359,392 $20,431,138 $34,483,200 $ 1,250,000 $62,523,730
------------ -------------- -------------------- -------------- -----------
------------ -------------- -------------------- -------------- -----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable........................... $ 824,400 $ 1,000,000(f) $ 1,824,440
Revenue distribution payable............... 74,325 74,325
Accrued expenses........................... 331,964 35,622(f) 367,586
Current portion of long-term debt.......... 988,360 564,338(f) $ 623,536(b) 2,176,234
------------ -------------- -------------- -----------
Total current liabilities.............. 2,219,089 1,599,960 623,536 4,442,585
Long-term debt............................... 1,846,165 1,714,730(b) 3,560,895
Non-recourse debt............................ 864,000 864,000
Accrued interest on non-recourse debt........ 227,114 227,114
------------ -------------- -------------- -----------
Total liabilities...................... 5,156,368 1,599,960 2,338,266 9,094,594
Stockholder's Equity:
Cumulative convertible preferred stock, $.01
par value.................................. 860 (860)(d) --
Common stock, $.01 par value................. 16,560 $ 101,567(c)(g) 118,127
Unamortized value of warrants issued......... (20,371) (20,371)
Paid-in capital.............................. 14,751,425 18,831,178 34,381,633(c)(g) (1,087,406)(d) 66,876,830
Retained deficit............................. (13,545,450) (13,545,450)
------------ -------------- -------------------- -------------- -----------
Total stockholders' equity............. 1,203,024 18,831,178 34,483,200 (1,088,266) 53,429,136
------------ -------------- -------------------- -------------- -----------
Total liabilities and stockholders' equity... $ 6,359,392 $20,431,138 $34,483,200 $ 1,250,000 $62,523,730
------------ -------------- -------------------- -------------- -----------
------------ -------------- -------------------- -------------- -----------
</TABLE>
26
<PAGE>
NOTES TO UNAUDITED PRO FORMA STATEMENTS OF OPERATIONS AND BALANCE SHEET
(a) Geological and geophysical, delay rentals and exploratory dry hole costs for
the year ended December 31, 1997 and the three months ended March 31, 1998
amounted to $5,519,673 and $1,256,767, respectively. These amounts are
related to properties with no proved reserves, and are charged to expense
under the successful efforts method of accounting, whereas they had been
previously capitalized by EPC and Aspect under the full cost method of
accounting. All other costs incurred by EPC and Aspect related to the
acquired prospects are leasehold acquisitions costs which are capitalized
for both full cost and successful efforts.
(b) In conjunction with the Acquisition Agreement, the Company entered into the
Initial Bridge Facility with Aspect Management Corporation on January 19,
1998, to provide bridge financing for operations and initial prospect
development. The principal amount of $1.8 million bore interest at 18.0%,
and was payable in twelve equal monthly installments including interest
beginning no later than March 31, 1998. Subsequently, on February 23, 1998,
also in conjunction with the Acquisition Agreement, the Company replaced the
Initial Bridge Facility with the $7.8 million Duke Credit Facility. The Duke
Credit Facility bears interest at prime plus 4% (initially 12.5%), and is
payable in eleven monthly installments equal to one thirtieth ( 1/30th) of
the outstanding principal on July 31, 1998, with the first of such
installments commencing on August 31, 1998, and continuing thereafter
through June 30, 1999, with the remaining principal outstanding balance due
on July 31, 1999. On the date of the execution of the Duke Credit Facility,
the outstanding amount on the Initial Bridge Facility was $500,000. This
amount was subsequently transferred to the Duke Credit Facility. In
addition, the Company redeemed its Preferred Stock as part of the
Acquisitions, and as such, has drawn on the Duke Credit Facility for the
funds necessary to redeem the Preferred Stock. The redemption price plus
accrued and unpaid dividends at December 31, 1997 was $1,088,266. This
amount combined with the current outstanding amount on the Duke Credit
Facility is $4,838,266. Interest expense associated with the borrowings was
$601,990 and $150,497 for the year ended December 31, 1997 and the three
months ended March 31, 1998, respectively. As of March 31, 1998, $1,290,204
was included as current portion of long-term debt, with the remaining
balance of $3,548,062 classified as long-term. To date, approximately $3.0
million of the outstanding amount has been used for prospect development,
with the remaining amounts used for operations.
(c) In connection with the Initial Bridge Facility discussed in Note (b), the
Company issued warrants to purchase 50,000 shares of Common Stock at an
exercise price of $3.00 per share. The $150,000 in proceeds from those
warrants are included in cash at March 31, 1998. In addition, $131,250 is
included in prepaid interest for the discount received between the grant
price and the market price on the date of the grant. Since the recipients
have guaranteed their pro rata share of the Duke Credit Facility, the
prepaid interest will be amortized over the term of the underlying debt of
17 months.
(d) In connection with the Acquisition Agreement discussed in Note (b) above,
the Company redeemed its Preferred Stock at a redemption price of $10.26 per
share including all accrued and unpaid dividends. At March 31, 1998, the
total redemption price for the 85,961 shares of outstanding Preferred Stock
was $1,088,266.
(e) Historical general and administrative expenses associated with personnel and
facilities of EPC that the Company assumed as a result of the Acquisitions
amounted to approximately $1,483,000 and $360,000 for the year and three
months ended December 31, 1997 and March 31, 1998, respectively.
(f) Additions to working capital include the following:
<TABLE>
<CAPTION>
ACQUIRED
ASSETS ADJUSTMENTS
-------------- ------------
<S> <C> <C>
Liabilities of EPC assumed by the Company.............................. $ (1,000,000)
Proceeds from Warrants................................................. $ 150,000
Accrued interest associated with EPC note payable to Aspect assumed by
the Company(1)....................................................... (35,622)
Transfer of advances to EPC to oil and gas properties.................. (466,664)
Accounts receivable from Aspect to EPC assumed by the Company.......... 564,338
Current portion of long-term debt...................................... (564,338) (617,576)
-------------- ------------
Total working capital (deficit)........................................ $ (1,035,622) $ (934,240)
-------------- ------------
-------------- ------------
</TABLE>
- --------------------------
(1) EPC and Aspect have interests in common oil and gas prospects. Aspect
advanced EPC amounts to develop and explore those prospects. The
entities have no common ownership or interests outside of those
prospects.
(g) The Company issued 10,106,702 shares of Common Stock in exchange for working
interests in undeveloped oil and gas prospects with a historical full cost
basis of $19,866,800 and estimated fair market value of approximately $54.2
million based on the Cornerstone Opinion.
(h) Upon closing of the Acquisition Agreement, advances made to EPC to fund the
exploration and development of the the acquired prospects that became assets
of the Company were transferred to oil and gas properties. These amounts are
included as notes receivable in the historical financial statements and
amount to $1,750,000, of which $466,664 is classified as current, with the
remaining balance of $1,283,336 classified as long-term.
27
<PAGE>
SELECTED FINANCIAL DATA
The following selected consolidated financial data as of December 31, 1996
and 1997 have been derived from the Company's audited consolidated financial
statements. The selected consolidated financial data as of and for the three
month periods ended March 31, 1997 and 1998 are derived from the Company's
unaudited consolidated financial statements. The unaudited consolidated
financial statements include all adjustments consisting of normal recurring
accruals that the Company considers necessary for a fair presentation of the
Company's financial position as of such dates and the results of operations and
cash flows for such periods. Operating results for the three months ended March
31, 1998 are not necessarily indicative of the results that may be expected for
the entire year ending December 31, 1998. Selected Financial Data should be read
in conjunction with the "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Financial Statements of the Company
and the related notes thereto included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER THREE MONTHS ENDED
31, MARCH 31,
---------------------- ---------------------
1996 1997 1997 1998
---------- ---------- ---------- ---------
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas revenues(1)......................................... $3,176,861 $ 664,126 $ 327,435 $ 48,503
Operating fees.................................................. 213,834 55,021 14,234 6,992
Other revenues(2)............................................... (223,903) 189,462 63,978 (72,081)
---------- ---------- ---------- ---------
Total revenues................................................ 3,166,792 908,609 405,647 (16,586)
---------- ---------- ---------- ---------
Costs and expenses:
Lease operating expense......................................... 556,925 427,240 96,698 69,773
Production taxes................................................ 207,969 24,497 8,784 (1,090)
Transportation and gathering costs.............................. 368,716 143,265 90,394 639
Depletion, depreciation and amortization(3)..................... 2,237,648 315,880 132,774 53,568
Impairment of oil and gas properties(5)......................... 51,000 349,384 -- --
Exploration costs(4)............................................ 1,317,161 2,258,702 852,626 3,560
Delay rentals(6)................................................ -- 211,690 -- (12,685)
Interest expense................................................ 783,872 60,942 4,133 19,223
General and administrative expense.............................. 2,217,099 2,070,812 572,260 459,014
Other costs and expenses(7) 451,421 -- -- --
---------- ---------- ---------- ---------
Total expenses................................................ 8,191,811 5,862,412 1,757,669 592,002
---------- ---------- ---------- ---------
Net loss...................................................... (5,025,019) (4,953,803) (1,352,022) (608,588)
Cumulative preferred stock dividend............................. 103,153 103,153 25,798 25,798
---------- ---------- ---------- ---------
Net income (loss) applicable to common stockholders............. $(5,128,172) $(5,056,956) $(1,377,810) $(634,376)
---------- ---------- ---------- ---------
---------- ---------- ---------- ---------
Net income (loss) per common share(8)......................... $ (4.31) $ (3.07) $ (0.84) $ (0.38)
---------- ---------- ---------- ---------
---------- ---------- ---------- ---------
Weighted average number of common shares(8)..................... 1,190,343 1,646,311 1,644,317 1,655,984
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------- AS OF MARCH 31,
1996 1997 1998
---------- ---------- -------------------
<S> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit).......................................... $4,159,034 $ (413,377) $(1,148,584)
Property and equipment, net........................................ 3,435,924 3,144,370 3,491,695
Total assets....................................................... 9,631,192 4,576,008 6,359,392
Long-term debt (excluding current maturities)...................... 1,069,886 1,080,954 2,893,055
Stockholders' equity............................................... 6,738,826 1,804,820 1,203,024
</TABLE>
- ------------------------------
(1) Oil and gas revenues decreased from $3.18 million in 1996 to $0.66 million
in 1997, and from $0.33 million for the three months ended March 31, 1997 to
$48,503 for the same period in 1998 primarily due to ceased production from
the Mobile Bay wells and the sale of producing properties.
(2) Other revenues increased from ($0.2) million in 1996 to $.2 million in 1997
primarily due to the gain on the sale of assets and a decrease in realized
losses on commodity transactions. Other revenues decreased from $63,978 for
the three months ended March 31, 1997 to ($72,081) for the same period in
1998 due to losses on commodity transactions.
(3) Depletion, depreciation and amortization decreased from $2.2 million in 1996
to $0.3 million in 1997 primarily due to the abandonment of previously
producing wells in the Mobile Bay prospect and the sale of certain oil and
gas properties.
28
<PAGE>
(4) Impairment of oil and gas properties increased from $51,000 in 1996 to
$349,384 in 1997 primarily due to the abandonment of previously producing
wells in the Mobile Bay prospect.
(5) Exploration costs and delay rentals increased from $1.3 million in 1996 to
$2.5 million in 1997 primarily due to the dry holes drilled in 1997.
Exploration costs and delay rentals decreased from $1.0 million for the
three months ended March 31, 1997 to ($9,125) for the same period in 1998
due to dry holes drilled in 1997.
(6) Interest expense decreased from $783,872 in 1996 to $60,942 in 1997
primarily due to the reduction in the Company's outstanding bank debt during
1997.
(7) 1996 includes other expense items for the purchase and settlement of
deferred gas contracts. There were no such expenses during 1997.
(8) Weighted average shares outstanding and net loss per common share have been
adjusted to reflect the 1:6 Reverse Split effected on May 14, 1998.
29
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis reviews the Company's operations for
the years ended December 31, 1997 and 1996 and for the three months ended March
31, 1998 and 1997, and should be read in conjunction with its consolidated
Financial Statements and related notes thereto.
OVERVIEW
On May 14, 1998, the Company (i) consummated the Acquisitions, and in
connection therewith, issued 10,906,702 shares of its Common Stock to EPC,
Aspect and certain other persons in exchange for the Exploration Projects and
certain overriding royalty interests therein; (ii) completed a one-for-six
Reverse Split of its Common Stock; (iii) reincorporated in the State of Delaware
and changed its name to Esenjay Exploration, Inc.; and (iv) called for
redemption all of its issued and outstanding Preferred Stock. The Company
believes that the consummation of the Acquisitions, along with the addition of
experienced staff and management (many of whom have worked together for over 15
years), and the implementation of its corporate restructuring, positions the
Company as a technology driven exploration company with a diverse array of
technology enhanced exploration projects. The Company also believes consummating
the Acquisitions will enhance its ability to access capital markets.
Since November 1, 1997, which was the effective date of the Acquisitions, 15
wells have been drilled for the Company's account. Of these wells, six have been
completed, four are awaiting completion and five were dry holes.
The opportunities set forth in the Company's Exploration Project portfolio
will require significant amounts of capital funding throughout the remainder of
1998 and into 1999. The Company's success in accessing this capital will have a
significant impact on its growth opportunities. See "--Liquidity and Capital
Resources."
The Company is on a successful efforts accounting basis, and booked the
Exploration Projects acquired pursuant to the Acquisition Agreement at their
estimated fair market value based on the Cornerstone Opinion. 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 has recognized the need to ensure its systems, equipment and
operations will not be adversely impacted by the change to the calendar year
2000. As such, the Company operates on an internally designed software package
that is compliant with the year 2000. The Company is attempting to identify
other potential areas of risk and has begun addressing these in its planning,
purchasing and daily operations. The total costs of connecting all internal
systems, equipment and operations to the year 2000 has not been fully
quantified, but it is not expected to be a material cost to the Company.
However, although no estimates can be made as to the potential adverse impact
resulting from the failure of third party service providers and vendors to
prepare for the year 2000, the Company intends to formulate a plan to deal with
potential year 2000 issues.
COMPARISON OF MARCH 31, 1998 TO MARCH 31, 1997
REVENUE. Total Revenues decreased 104.09% from $405,647 for the quarter
ended March 31, 1997 to a negative $16,586 for the quarter ended March 31, 1998.
Total gas and oil revenues decreased 85.19% from $327,435 to $48,503. The
decrease in gas and oil revenues was primarily attributable to ceased production
for the Mobile Bay wells which came on stream in December of 1995. Gas and oil
revenues associated with Mobile Bay declined from $131,087 for the quarter ended
March 31, 1997, compared to no revenues for the quarter ended March 31, 1998. A
30
<PAGE>
contributing factor to the decline in gas and oil revenues was the sale of other
interests and gas price fluctuations. The negative $16,586 resulted from a
realized loss on commodity transactions of $47,875 in the quarter. The Company
recorded gas and oil revenues associated with these other interests of $46,696
for the quarter ended March 31, 1997.
Gain on sale of assets decreased by $129,160 from $132,035 in the first
quarter 1997 to $2,875 in the first quarter of 1998. Operating fees to the
Company decreased from $14,234 in the first quarter of 1997 to $6,992 in the
first quarter of 1998. The Company realized losses from various commodity
transactions totaling $47,875 in the first quarter of 1998, compared to $121,937
in the first quarter of 1997. These swap agreement losses were attributable to
various transactions in which the Company hedged its future gas delivery
obligations as a requirement for its Bank Credit Agreement. The determination of
gains or losses is directly affected by the spot gas prices being higher or
lower than the hedge contracts in place for the same period. In addition to the
realized losses from commodity transactions, the Company accrued $51,011 for
unrealized losses for the quarter ended March 31, 1998. There were no accrued
losses for the quarter ended March 31, 1997. In addition to the foregoing, the
Company had other revenues of $23,930 in the first quarter of 1998 as compared
to $53,880 in the first quarter of 1997.
COSTS AND EXPENSES. Total costs and expenses of the Company decreased
66.36% from $1,757,669 in the first quarter of 1997 to $592,002 in the first
quarter of 1998. The decrease in costs and expenses was primarily attributable
to a combination of decreases in exploration costs, general and administrative
expenses, transportation and gathering costs, depletion, depreciation and
amortization expense, lease operating expense and production taxes. These
decreases were offset by interest expense increases.
Exploration costs decreased 99.58% from $852,626 for the first quarter of
1997 to $3,560 for the first quarter 1998. The exploration costs for the first
quarter 1998 reflect charges attributable to expensed investments, and costs
incurred for dry hole costs associated with exploratory drilling in 1997.
General and administrative expense ("G&A") decreased by 19.79% from $572,260
for the first quarter 1997 to $459,014 for the first quarter 1998. The decrease
was attributable to overhead reduction measures initiated during 1997.
Transportation and gathering costs decreased 99.29% from $90,394 for the
first quarter 1997 to $639 for the first quarter 1998. The decrease was almost
entirely attributable to the ceased production of the Mobile Bay wells.
Depletion, Depreciation and Amortization Expense ("DD&A") decreased by
59.65% from $132,774 for the first quarter of 1997 to $53,568 for the first
quarter of 1998. The decrease was primarily attributable to the July 1, 1997
sale of certain Company properties located in Texas, Oklahoma and Arkansas, and
the ceased production from the Mobile Bay wells.
Lease operating expense decreased 27.84% from $96,698 for the first quarter
1997 to $69,773 for the first quarter 1998. The reduction was attributable to
the sale of certain Company properties effective July of 1997, and a decline in
rework activity.
Production taxes declined 112.40% from $8,784 for the first quarter of 1997
to ($1,090) for the first quarter of 1998, due to reduced production as a result
of the sale of certain Company interest effective July 1, 1997, and due to a
production tax credit refund in the amount of $3,682 from the State of Oklahoma
for a production enhancement project completed August 17, 1994.
Interest expense increased 365.11% from $4,133 for the first quarter of 1997
to $19,223 for the first quarter of 1998. The increase was primarily attributed
to the Duke Credit Facility. The Company capitalized a large portion of its
interest in its Starboard Prospect, which capitalized amounts totaled $79,102
for the first quarter of 1998 and $56,866 for the first quarter of 1997.
NET INCOME (LOSS). The net loss decreased from $1,352,022 to $608,588 for
the first quarter ended March 31, 1997 and March 31, 1998, respectively. This
decrease was due to the factors discussed above.
31
<PAGE>
The net loss per common share decreased from a net loss of $0.84 per share
in the first quarter of 1997 to a net loss of $0.38 per share in the first
quarter of 1998, computed on a post-Reverse Split basis. This is reflective of
the increase in net loss of $743,434 from the first quarter of 1997 as compared
to the first quarter of 1998. As a result of the Common Stock offering completed
on August 14, 1996, and additional stock issued to an investment advisor during
1997, there were 1,655,984 weighted average common equivalent shares at March
31, 1998 as compared to approximately 1,644,317 at March 31, 1997.
COMPARISON OF 1997 TO 1996
REVENUE. Total revenues decreased 71.3% from $3,166,792 for the year ended
December 31, 1996, to $908,609 for the year ended December 31, 1997.
Total gas and oil revenues decreased 79.1% from $3,176,861 to $664,126. The
decrease in gas and oil revenues was primarily attributable to ceased production
from the Mobile Bay wells, which came on stream in December of 1995, and from
the sale of properties discussed below. A contributing factor in the decline in
gas and oil revenues was the sale of the Company's N.E. Cedardale field located
in Major County, Oklahoma in September 1996. The Company recorded gas and oil
revenues associated with these factors of $2,003,251 for 1996 and $62,471 for
1997. The remainder of this decrease is primarily attributable to sales of other
interests and gas price fluctuations. Operating fees to the Company decreased
from $213,834 for the year 1996 to $55,021 for the year 1997, due to the sale of
a substantial portion of the Company's operated properties. The decrease in gas
and oil revenues was partially offset by an increase in gain on sale of assets
of $201,583, from $250,437 reported for 1996, to $452,020 reported for 1997. The
increase is due to the sell down of certain Company prospects and the sale of
certain Company properties located in Texas, Oklahoma and Arkansas. The Company
realized losses from various commodity transactions totaling $375,410 for the
year ended December 31, 1997. The decrease in the loss is primarily attributable
to the amended swap agreement with Bank of America in September of 1996, which
decreased the volume of the swap agreements. This compares to a realized loss of
$814,029 for the same period 1996. Settlement costs in connection with the
amendment to the swap agreement with Bank of America totaling $212,000 are
included in the 1996 realized losses from commodity transactions. These swap
agreement losses were attributable to various transactions in which the Company
hedged its future gas delivery obligations as a requirement under the Bank
Credit Agreement. The determination of gains or losses is directly affected by
the spot gas prices being higher or lower than the hedge contracts for the same
period. In addition to the realized losses from commodity transactions, the
Company accrued $128,936 for unrealized losses for the year ended December 31,
1997. This was the amount by which the hedges in place exceeded the production.
There were no accrued losses at December 31, 1996. The Company also had other
revenues of $241,788 for the year ended December 31, 1997 as compared to
$339,689 for the year ended December 31, 1996. The reduction is primarily
attributable to reduced revenues realized from the performance of exploratory
and geophysical data processing on a fee basis. Included in the year ended
December 31, 1997 other revenue is a net gain of $25,794 from the Company's
officers deferred compensation settlement, which was executed on August 15,
1997.
COSTS AND EXPENSES. Total costs and expenses decreased 28.4% from $8,191,811
in 1996 to $5,862,412 in 1997. Although there were increases in exploration
costs, delay rentals and unrealized loss on commodity transactions there were
decreases in lease operating expenses, production taxes, transportation,
depreciation, interest expense, cost of settling gas contracts and futures
contracts and general and administrative expenses, which resulted in the net
decrease as more fully described below.
Exploration costs increased 71.5% from $1,317,161 in 1996 to $2,258,702 in
1997. The exploration costs in 1997 reflect $380,464 of charges attributable to
expensed investments, and $1,772,746 of dry hole costs. The increase was due to
increased exploratory drilling.
32
<PAGE>
Delay rental transactions were $211,690 for the year ended December 31,
1997. This increase was primarily attributed to rental obligations of the
Company's Starboard Project in Terrebonne Parish, Louisiana. There were no such
transactions for the same period in 1996.
Lease operating expense decreased 23.3% from $556,925 in 1996 to $427,240 in
1997. The reduction in lease operating costs was attributable to the sale of
operated properties, including the N.E. Cedardale field sale in September of
1996, and a decline in rework activities. Of the year ended December 31, 1997
total lease operation costs, $99,809 was attributable to plugging and
abandonment costs of the Company's Mobile Bay wells, which were plugged during
1997. Production taxes declined 88.2% from $207,969 in 1996 to $24,497 in 1997
due to reduced production as a result of the sale of certain of the Company's
properties, including the N.E. Cedardale field and other properties in Texas,
Arkansas and Oklahoma.
Transportation and gathering costs decreased from $368,716 in 1996 to
$143,265 in 1997. The decrease was almost entirely attributable to the ceased
production of the Mobile Bay wells.
DD&A expense decreased by 85.9% from $2,237,648 in 1996 to $315,880 in 1997.
The decrease was primarily attributable to the sale of certain of the Company's
properties, including the N.E. Cedardale field.
Interest expense decreased to $60,942 in 1997 from $783,872 in 1996. The
decrease was primarily attributable to the substantial loan principal repayment
made to Bank of America under the Credit Agreement. During 1997, the Company
capitalized a large portion of its interest in its ongoing Starboard Project,
which capitalized amounts totaled $107,387 in 1996 and $235,977 in 1997.
Cost of settling gas contracts and futures contracts was attributable to the
settlement of a gas sales contract with Waldorf Corporation ($368,690) and the
settlement of a gas swap agreement, due to a reduction in quantities covered
thereunder in connection with the sale of the N.E. Cedardale field ($212,000)
for the year ended December 31, 1996. The Company incurred no similar costs in
1997.
G&A expenses decreased by 6.5% from $2,217,099 in 1996 to $2,070,812 in
1997. This was primarily attributable to overhead reduction measures initiated
during 1997.
Impairment of Oil and Gas Properties increased from $51,000 in 1996 to
$349,384 in 1997. This was primarily due to the abandonment of previously
producing wells, of which $323,353 was attributable to the Company's Mobile Bay
wells.
NET INCOME (LOSS). The net loss decreased from $5,025,019 to $4,953,803 for
the year ended December 31, 1996, and December 31, 1997, respectively. This
decrease was due to the factors discussed above.
The net loss per common share decreased from a net loss of $4.31 per share
in 1996 to a net loss of $3.07 per share in 1997, computed on a post-Reverse
Split basis. This is reflective of the decrease in the net loss of $71,217 from
the year ended December 31, 1996 to the year ended December 31, 1997 and a
change in the number of weighted average equivalent shares outstanding. As a
result of the Common Stock offering finalized on August 14, 1996, there were
approximately 1,646,311 weighted average common equivalent shares at December
31, 1997, as compared to approximately 1,190,343 weighted average common
equivalent shares at December 31, 1996.
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 properties acquired in the
Acquisitions, as well as the Starboard Project and other prospects. Because the
Company divested substantially all of its oil and gas properties in the
Mid-Continent region by the end of 1996, revenues from the operation and sale of
such properties have been substantially reduced during 1997 and will be reduced
in future years. Further, following a sharp and unexpected drop in production
from the Company's Mobile Bay wells during the fourth quarter of 1996,
33
<PAGE>
the Company's share of revenues from Mobile Bay was substantially reduced during
1997. Revenues from the operation of the Mid-Continent and Mobile Bay properties
and the sale of Mid-Continent properties constituted the substantial majority of
the Company's revenues during 1996.
As a result of the loss of revenues from the Mid-Continent region and Mobile
Bay, the Company's revenues during 1997 were sharply reduced. While management
believes that the Acquisitions and the Starboard Project represent the most
promising prospects in the Company's history, none of those prospects are
currently producing revenue to the Company, and each will require substantial
outlays of capital to explore, develop and produce.
LIQUIDITY AND CAPITAL RESOURCES
The Company has budgeted $25.0 million to fund the drilling of approximately
30 wells on the Exploration Projects and other exploration costs over the next
12 months. The Company's sources of financing include the proceeds of this
Offering, the borrowing capacity under the Bank Credit Agreement and other
credit facilities, the sale of promoted interests in the Exploration Projects to
industry partners and cash provided from operations. The Company anticipates it
will receive approximately $14.2 million in net proceeds from this Offering. Of
such proceeds, $7.8 million will be used to repay the Duke Credit Facility, and
the remainder will be used for exploration activities on the Exploration
Projects, including the payment of approximately $4.755 million of the aggregate
$7.755 million of costs incurred by Aspect and EPC on the Exploration Projects
before the closing of the Acquisition, $6.25 million in additional exploration
costs incurred as of the date hereof, and for working capital and general
corporate purposes. Based on the foregoing, the Company will require additional
sources of capital to fund its exploration budget over the next 12 months. The
Company currently is attempting to renegotiate the terms of the Bank Credit
Agreement to obtain additional borrowing capacity thereunder. If the Company is
unable to obtain such additional borrowing capacity thereunder, or is unable to
access additional sources of outside financing, the Company will either have to
sell interests in its Exploration Projects to fund its exploration program or
curtail its exploration activities over the next 12 months. Such curtailing of
exploration activities could include reducing the number of wells drilled,
slowing exploratary activities on projects that the Company operates, selling
interests in the Company's project inventory or a combination of the foregoing.
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 31, 1998, consisted principally of (i) servicing loans under the Bank
Credit Agreement and other loans, (ii) servicing the Duke Credit Facility; (iii)
servicing the Starboard Project Financing, (iii) payment of preferred stock
dividends, (iv) funding of the Company's exploration activities, and (v) funding
of the day-to-day general and administrative costs. The Company also had
unrealized losses on commodity transactions of $179,947 for the period ended
March 31, 1998.
The Company booked the assets acquired in the Acquisitions at $54.2 million,
which was the estimated fair market value of such assets as determined by
Cornerstone. Items effected by the Acquisitions include (i) an increase in the
Company's current liabilities by the assumption of approximately $4.755 million
of net post-effective date costs related to the assets acquired in the
Acquisitions, plus $1 million of additional current liabilities assumed from EPC
pursuant to the Acquisition Agreement, (ii) an increase in overhead resulting
from the hiring of additional technical staff and additional management; and
(iii) adopting a business plan that budgets over $25.0 million net to the
Company's interest in exploratory costs over the next 12 months. Certain costs
associated with these obligations may be offset by future revenues from wells
drilled since the effective date of the Acquisitions and other revenue
anticipated from wells scheduled to be drilled in the second and third quarters
of 1998. The Company cannot, however, assure that such revenues will be
forthcoming, nor can it project the revenues anticipated from such sources over
the next 12 months.
34
<PAGE>
Many of the factors that may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control, including,
but not limited to, oil and natural gas prices, governmental actions and taxes,
the availability and attractiveness of financing and its operational results.
The Company continues to examine alternative sources of long-term capital,
including 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.
WORKING CAPITAL. At March 31, 1998, the Company had a cash balance of
$188,495 and a working capital deficit of $1,148,584 as compared to a cash
balance of $690,576 and a working capital deficit of $413,377 at December 31,
1997. The decrease in cash and working capital was primarily attributable to the
operating loss incurred during the quarter.
In addition to the changes in cash, the decrease in working capital was
attributable to several other factors. Current asset decreases of $45,357 in
accounts receivable (due to reduced exploration activity) and $108,254 in
prepaid and other expenses (primarily due to expensing of previously prepaid
amounts related to the Starboard Project) were offset by the $466,664 current
portion of notes receivable from affiliates. These notes represented the current
portion of loans from the Company to EPC that were used to fund post-effective
date costs on Exploration Projects acquired from EPC. Primary changes in current
liabilities were a $86,956 reduction in accounts payable (due to reduced
exploration activity) and a $587,275 increase in the current portion of
long-term debt, which relates to the current portion of debt under the Duke
Credit Facility.
CASH FLOWS. Cash flows used in operations totaled $756,522 for the quarter
ended March 31, 1998. Of particular significance is a cost of $344,896 in other
assets, which primarily relates to capitalized costs of the Acquisitions and
certain financing transactions. Cash flows used in investing activities totaled
$2,151,578. Cash flows used in investing activities included $403,250 of capital
expenditures on gas and oil properties, including $3,560 in exploration costs
that were included in the operating loss for the period but were excluded from
operating cash flows, and $1,750,000 that represents a note receivable from EPC.
Cash flows from financing activities reflected cash provided by financings
of $2,406,019 for the first quarter of 1998. Cash flows from financing
activities consisted of proceeds from debt issuance of $3,000,000 from the Duke
Credit Facility offset by repayments on long-term debt of $593,981.
Set forth below is a description of the Company's credit facilities.
BANK CREDIT AGREEMENT. The Bank Credit Agreement is a $15.0 million credit
facility with Bank of America NT&SA as lender. As of July 15, 1998, the Company
had $168,888 outstanding under the Bank Credit Agreement and had $2.5 million of
additional borrowing capacity thereunder. The borrowing capacity under the Bank
Credit Agreement is subject to reduction based upon the value of the oil and gas
properties securing the loans thereunder. The Bank Credit Agreement is secured
by a first mortgage on all of the Company's proved producing properties owned as
of March 31, 1998. The Company does not currently intend to borrow additional
amounts under this facility, but has begun discussions with the lender to
restructure the facility to more appropriately serve the Company's current and
anticipated needs throughout the balance of this year. The lender has indicated
an intention and desire to do so, but no agreement has yet been reached, and
there is no assurance that such an agreement will be forthcoming. The Company
presently is in noncompliance with the minimum cash flow covenants of the Bank
Credit Agreement, but has secured a waiver of various covenants through June 30,
1998. The Company anticipates that the lender will waive the noncompliance in
the future, but there is no current assurance that it will do so.
The Bank Credit Agreement required the Company to enter into a swap
agreement on 62,500 MMBtu of its monthly Mid-Continent natural gas production
for $1.566 per MMBtu for the period
35
<PAGE>
beginning April 1, 1996 and ending January 31, 1999. The swap, which is the
Company's only current hedge, was reduced to 31,250 MMBtu on September 25, 1996,
in connection with the sale of the N.E. Cedardale field. The Company recorded a
loss of $212,000 on this swap reduction. The Company's net gas production
currently is less then the volumes hedged. As of December 31, 1997, the Company
had an accrued liability of $128,936 to recognize the projected loss from the
hedge. The Company has not recently conducted an active hedging program other
than as required by the Bank Credit Agreement. In that regard, the Company had
net losses of $814,029 in 1996, which includes the $212,000 loss on the swap
reductions, and $375,410 in 1997 on its required hedged positions.
THE DUKE CREDIT FACILITY. The Duke Credit Facility is a $7.8 million
facility that can be used for certain defined purposes. As of July 15, 1998, the
Company has borrowed $7.8 million under the Duke Credit Facility. Of the $7.8
million borrowed, $1.25 million was used for general corporate purposes and
costs of exploration, and $3.0 million was loaned to EPC to pay exploration
costs associated with EPC's interests in the Exploration Projects conveyed by
EPC to the Company upon closing of the Acquisitions and $1.1 million was used to
fund the redemption of the Preferred Stock, and an additional $2.45 million was
used to fund exploration costs and working capital.
The Duke Credit Facility bears interest at the rate of a national prime rate
plus 4% per annum. The lender also receives cash payments equal to an overriding
royalty of 0.6% of the Company's interest in wells drilled by the Company while
the Duke Credit Facility is outstanding. In addition, the lender has the right
to gather, process, and transport and market, at competitive market rates,
natural gas produced from a majority of the projects the Company acquired
pursuant to the Acquisitions until the earlier to occur of five years from the
date of the Duke Credit Facility or until the lender has marketed one hundred
Bcf of natural gas from those properties. The Duke Credit Facility is secured by
mortgages on most of the Company's undeveloped exploration projects. The Duke
Credit Facility is repayable in 12 monthly payments commencing August 31, 1998,
or sooner, if the borrower sells interests in the collateral or closes any
underwritten public offering of securities. A portion of the proceeds of this
Offering will be used to repay the Duke Credit Facility in full. See "Use of
Proceeds."
STARBOARD PROJECT FINANCING. The Starboard Project Financing is an $864,000
facility pursuant to which the lender has agreed to advance to the Company an
amount equal to up to 50% of certain costs related to the development of the
Starboard Project, including acquisition of leasehold interests and the design,
permitting and implementation, conducting, processing and interpretation of a
3-D seismic survey over the Starboard Project area. The borrowings are secured
by a first mortgage on the properties comprising the Starboard Project.
Borrowings under the Starboard Project Financing are repayable solely from
revenues attributable to an overriding royalty interest granted to the lender
equal to 8% of the Company's original interest in the Starboard Project, which
is payable until such time as the lender has received an amount equal to the
loan borrowings plus costs and a 15% internal rate of return. After such funds
have been repaid, the overriding royalty interest is reduced to 2%. The Company
has drawn its entire borrowing capacity under the Starboard Project Financing,
therefore, Starboard Project Financing will not be available to provide
additional funds for development of the Starboard Project.
The Company expects that if it does not complete this Offering or secure
additional financing or other sources of capital it will deplete its current
cash reserves and fully use its credit facilities by the third quarter of 1998.
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 financial statements. In 1997,
FASB also issued SFAS No. 130, "Reporting Comprehensive Income" and SFAS No.
131, "Disclosures about Segments of an Enterprise and Related Information," each
of which require expanded disclosures effective for 1998. The Company does not
expect the application of these statements to have a material effect on its
financial position, liquidity or results of operations.
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BUSINESS AND PROPERTIES
GENERAL
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 over 30 technology enhanced natural gas Exploration Projects along the Texas
and Louisiana Gulf Coasts. These Exploration Projects include substantial
interests in 28 projects the Company acquired on May 14, 1998 pursuant to the
Acquisition Agreement. Cornerstone delivered to the Company a written opinion
that estimated the fair market value of the assets acquired in the Acquisitions,
as of January 23, 1998, to be $54.2 million. See "Risk Factors-- Uncertainty as
to Estimates of Fair Market Values." The Exploration Projects also include the
Company's interest in the Starboard Project in Terrebonne Parish, Louisiana,
which consists of mineral leases and options and a proprietary 3-D seismic
survey over the Lapeyrouse Field. The Company, EPC and Aspect have spent several
years identifying and evaluating many of the Exploration Projects.
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 Acquisitons and this exchange, EPC, Aspect and the
Enron affiliate own 43.91%, 36.27%, and 5.74%, respectively, of the Company's
Common Stock.
Most of the Exploration Projects have been, are being, or will be enhanced
with 3-D seismic data in conjunction with CAEX technologies. The 3-D seismic
data acquired, when complete, will cover approximately 1,500 square miles. A
significant number of the Exploration Projects have reached the drilling stage,
and the Company has budgeted approximately $25.0 million, in addition to funds
already spent, to fund the drilling of approximately 30 wells and to fund other
exploration costs over the next 12 months. The Company believes that its
Exploration Projects represent a diverse array of technology enhanced, 3-D
seismic confirmed, ready to drill natural gas exploration projects.
From November 1, 1997 (the effective date of the Acquisitions) through the
date hereof, approximately $4.91 million has been spent for the Company's
account on drilling and completion costs on the Exploration Projects. The
expenditures have funded costs of the Company's interests in 15 exploratory
wells, of which six have been completed, four are awaiting completion and five
were dry holes.
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
dominant position, the
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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, landmen and other
technical personnel. After the Acquisitions, the Company hired most of EPC's
technical personnel, who, in some instances, have worked together for over
15 years. In addition, the Company has entered into a geotechnical services
consulting agreement with Aspect on certain of the exploration projects
pursuant to which Aspect provides 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 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 acquired 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 many of the
Exploration Projects in which it does not own a majority interest, in most
cases, the Company owns a greater interest than any of its project partners.
As a result, in most of its Exploration Projects, the Company will 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 be the operator of most of
the wells drilled within the Exploration Projects.
Concurrent with the closing of the Acquisitions, the Company took several
steps to further its newly implemented business strategy. The Company changed
its name from Frontier Natural Gas Corporation to Esenjay Exploration, Inc., so
it would be identified with its exploration activities. It completed a
one-for-six reverse stock split that provided adequate available shares to issue
to close the Acquisitions and conduct its business into the future. In addition,
the Company reincorporated in Delaware, the leading state for incorporations in
the United States and the one it believes has the most extensive and
well-developed body of corporate law. The Company believes that the consummation
of the Acquisitions, along with the addition of experienced staff and management
(many of whom have worked together for over 15 years),
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and the implementation of its corporate restructuring, positions the Company as
a technology driven exploration company with a diverse array of technology
enhanced projects.
EXPLORATION PROJECTS
The Exploration Projects include substantial interests in 30 projects
located primarily along the Texas Gulf Coast. Through March 31, 1998, EPC and
Aspect had incurred historical exploration and development costs of $19,866,800
on the projects acquired in the Acquisitions, and the Company had incurred
historical exploration and development costs of $2,185,000 on the Starboard
Project. These costs include costs associated with leasehold acquisitions,
geological and geophysical analysis, delay rentals and dry hole costs. Most of
the Exploration Projects have been, are being, or will be enhanced with 3-D
seismic data and CAEX technologies. The 3-D seismic data acquired will, when
complete, cover approximately 1,500 square miles.
Many of the Exploration Projects acquired in the Acquisitions have
participants other than EPC and Aspect. EPC delivered over 90% of its interests
in its contributed Exploration Projects to the Company and retained the balance.
Aspect delivered 100% of its interests in several Exploration Projects and
delivered at least 50% of its interest in most of its remaining contributed
Exploration Projects. EPC and Aspect are responsible for their pro rata costs
attributable to their retained interests.
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 in which the Company believes offers
drilling opportunities in the Hackberry (Frio) 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:
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EXPLORATION PROJECTS
<TABLE>
<CAPTION>
ACRES LEASED OR UNDER
OPTION AT MAY 15,
1998(1) SQUARE MILES OF 3-D
---------------------- SEISMIC DATA RELATING
PROJECT AREAS GROSS NET TO PROJECT AREA (2) PROJECT INTEREST
- --------------------------------------------- --------- ----------- ----------------------- -----------------
<S> <C> <C> <C> <C>
SOUTH TEXAS
DOWNDIP FRIO CORE AREA
Big Gas Sand............................... 24,700 5,557 65 22.5%
Blessing................................... 10,672 2,471 22 24.0%
Tidehaven.................................. 9,145 1,742 28 40.5%
El Maton................................... 7,277 3,044 29 46.5%
Midfield................................... 2,228 569 21 37.5%
Matagorda I(3)............................. 11,444 6,879 50 74.0%
Matagorda II(4)............................ 7,480 3,859 60 66.0%
Southwest Pheasant......................... 10,000 7,500 10 75.0%
Geronimo................................... 9,616 1,792 76 20.0%
Houston Endowment.......................... 3,969 1,071 50 27.0%
Wolf Point................................. 1,520 546 8 45.5%
Sheriff Field.............................. 54,000 40,500 72 75.0%
West Jeffco................................ 13,500 6,075 60 45.0%
La Rosa.................................... 7,689 589 25 8.0%
Piledriver................................. 640 400 2 62.5%
WILCOX CORE AREA
Hall Ranch................................. 8,510 3,521 57 41.5%
Hordes Creek............................... 6,972 2,601 25 41.5%
Mikeska.................................... 7,239 2,490 31 38.0%
Duval, McMullen............................ 1,979 1,781 12 90.0%
TEXAS HACKBERRY CORE AREA
Lox B...................................... 11,700 2,925 71 25.0%
West Port Acres............................ 800 100 21 12.5%
Big Hill/Stowell........................... 10,000 5,000 56 50.0%
East Jeffco................................ 24,000 12,000 65 50.0%
West Beaumont.............................. 11,200 700 23 6.25%
LOUISIANA
Starboard.................................. 6,682 5,905 35 12.0%-48.0%
Tack....................................... 480 300 12 75.0%
OTHER TEXAS
Willacy County............................. 11,485 8,784 50 78.875%
Caney Creek................................ 21,000 2,625 32 12.5%
East Texas Pinnacle Reef(5)................ -- -- 400 --
MISSISSIPPI
Thompson Creek............................... 1,325 512 12 56.0%
Lipsmacker................................... 5,758 943 64 22.0%
--------- ----------- -----
Total.................................... 303,010 132,781 1,544
--------- ----------- -----
--------- ----------- -----
</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) Represents 3-D seismic data acquired or to be acquired. See "--Exploration
Projects--Exploration Project Descriptions."
(3) The Company has entered into an agreement to sell a 26.7% Project Interest
in this Exploration Project for $694,200 for costs incurred before
commencement of drilling operations.
(4) The Company has entered into an agreement to sell a 26.7% Project Interest
in this Exploration Project for $694,200 for costs incurred before the
commencement of drilling operations.
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(5) 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 on
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 were determined
as of the date of this Prospectus. 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
BIG GAS SAND. The Company has a 22.5% Project Interest in this 3-D seismic
project, which consists of approximately 24,700 gross (5,557 net) acres of
leases and options in Galveston County, Texas. The primary geological areas the
Company has identified for potential drilling are the Frio and Vicksburg sands.
An onshore seismic survey is scheduled for mid-1998. The estimated cost to drill
and complete a shallow well is approximately $900,000 with deeper wells costing
over $3.5 million.
BLESSING. The Company has a 24.0% Project Interest, which consists of
approximately 10,672 gross (2,471 net) acres of leases and options under 22
square miles of 3-D seismic coverage in Matagorda County, Texas. A 3-D seismic
survey was conducted in conjunction with the Tidehaven 3-D shoot. See
"--Tidehaven Project". The Company has generated several upper Frio prospect
leads from this 3-D data set. The Company has drilled an upper Frio Sands well.
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%. The deepest
pay zone in the well currently has been flow tested at a rate exceeding two
million cubic feet of gas and 35 bbls of condensate per day. The Company
believes other pay zones exist up-hole and are behind pipe. The estimated costs
of drilling and completing a shallow well in this project area are approximately
$550,000. The estimated cost to drill and complete a deep well is approximately
$1.3 million.
TIDEHAVEN. The Company has a 40.5% Project Interest, which consists of
leases and options covering over 9,145 gross (1,742 net) acres in Matagorda
County, Texas. These leases overlay a series of known field pays and multiple
fault blocks made this structure a 3-D seismic candidate. Initial interpretation
of the 28 square mile 3-D seismic data set is nearly complete. The Company has
drilled and has completed or is completing two wells in the lower Frio. The
estimated cost to drill and complete a well ranges from approximately $550,000
to $1.5 million, depending upon depth.
EL MATON. The Company has a 46.5% Project Interest, which consists of
leases and options covering approximately 7,277 gross (3,044 net)acres in
Matagorda County, Texas. A 29 square mile 3-D seismic survey was started in late
May 1997 as an extension of the Tidehaven shoot. This seismic survey has been
completed and is in the interpretation phase. The geologic setting and target
zones are the same as for Tidehaven. The Company believes that the information
obtained at Tidehaven will benefit the El Maton Project. The Company has
identified several 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 Company has a 37.5% Project Interest, which consists of
leases and options covering approximately 2,228 gross (569 net) acres in
Matagorda County, Texas. 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 El Maton
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 has
been disappointing for the zones that have historically been productive in the
area; however, the data has revealed two potential shallow drilling locations.
These locations require additional geological interpretation before drilling can
be scheduled. The estimated cost to drill and complete a well is approximately
$550,000.
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MATAGORDA I. The Company has a 74.0% Project Interest, which consists of
approximately 11,444 gross (6,879 net) acres of lease options in Matagorda
County, Texas. Review of existing 2-D seismic data suggests to the Company that
several undrilled fault segments may exist. The Company believes that deeper
sand objectives have not been adequately tested. A 3-D seismic survey is
scheduled for mid-year 1998 as part of an adjacent project. See "--Matagorda II
Project". The Company has entered into an agreement to sell a 26.7% Project
Interest in this project for $675,000 through pre-drilling. The estimated cost
to drill and complete a shallow well is approximately $550,000, with deeper
wells costing approximately $1.3 million.
MATAGORDA II. The Company has a 66.0% Project Interest, which consists of
approximately 7,480 gross (3,859 net) acres of lease options in Matagorda
County, Texas. A 1,000 acre wildcat prospect has been identified for the entire
package of Tex Miss sands. In addition, two exploitation/development prospects
have been generated within the project area and are scheduled for a 3-D seismic
survey mid-year 1998. The Matagorda II 3-D seismic shoot will be completed in
conjunction with the Matagorda I Project. The Company has entered into an
agreement to sell a 26.7% Project Interest in this project for $675,000 through
pre-drilling. The estimated cost to drill and complete a shallow well is
approximately $550,000, with deeper wells costing approximately $1.3 million.
SOUTHWEST PHEASANT. The Company has a 75.0% Project Interest, which
consists of 10,000 gross (7,500 net) acres of lease options in Matagorda County,
Texas. The primary target objectives are the middle and lower Frio sands. A
portion of the project area is covered by an old Mobil 3-D seismic survey that
has been reprocessed and reinterpreted. The Company has identified several
shallow prospects. Interpretation of deeper formations is not yet complete. The
estimated cost to drill and complete a shallow well is approximately $550,000,
with deeper wells costing approximately $1.3 million.
GERONIMO. The Company has a 20.0% Project Interest, which consists of
approximately 9,616 gross (1,792 net) acres of leases and options in San
Patricio County, Texas. A 76 square mile 3-D seismic survey has been shot, and
the Company has identified several prospective drillsites. One well has been
drilled that is currently being completed in one of two potential pay sands, and
is currently testing at a rate of approximately 66 bbls of oil and 108 Mcfgd. A
deep Vicksburg test well is currently scheduled to be drilled in 1998. The
estimated cost to drill and complete a well is approximately $600,000 for a
shallow well and approximately $1.2 million for an intermediate depth well, with
deeper Vicksburg wells costing over $4.0 million.
HOUSTON ENDOWMENT. The Company has a 27.0% Project Interest, which consists
of approximately 3,969 gross (1,071 net) acres of leases and options in San
Patricio and Aransas Counties, Texas. A 50 square mile 3-D seismic survey has
been acquired. EPC drilled one dry hole within the project area before execution
of the Acquisition Agreement. The Company believes the dry hole provided
subsurface data that has set up an updip location to be drilled. The Company
plans to drill two wells within the project area in 1998. The first well has
been drilled. It logged 15 feet of net pay and currently is awaiting testing and
completion. Additionally several shallow and deep prospects remain to be
drilled. 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 Company has a 45.5% Project Interest, which consists of
approximately 1,520 gross (546 net) acres of state leases in Calhoun County,
Texas. EPC drilled and completed five successful wells within the 3-D seismic
survey area before the Effective Date of the Acquisitions. The prospects require
directional drilling. Known field pays from this area are from the 7,200 foot
Frio, 7,500 foot Frio, 7,700 foot Frio, Broughton, Oats, Upper Middle and Lower
Melbourne sands. Additional geophysical interpretation is being conducted in an
attempt to identify direct hydrocarbon indicators. The Company has delineated
several potential drill sites. The estimated cost to drill and complete a well
is approximately $900,000.
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SHERIFF FIELD. The Company has a 75.0% Project Interest, which consists of
approximately 54,000 gross (40,500 net) acres of lease options in Calhoun
County, Texas. The Company believes this area is lightly explored for part of
the Lower Frio and Vicksburg formations southwest of Lavaca Bay. An independent
oil company has contracted to purchase this acreage block, which has not yet
been shot with 3-D seismic. This sale would net the Company approximately $1.2
million if consummated; however, the party that contracted to purchase such
acreage block has refused to close the transaction. Although Aspect has
instituted legal proceedings to compel the closing of the transaction, there can
be no assurance that Aspect will be successful in such proceedings.
WEST JEFFCO. The Company has a 45.0% Project Interest, which contains
13,500 gross (6,075 net) acres of lease options in Jefferson County, Texas.
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. Before drilling, the Company plans to shoot a 3-D seismic survey
that is scheduled to start in the third quarter of 1998. The estimated cost to
drill and complete a shallow well is approximately $650,000, with deeper wells
costing approximately $1.6 million.
LA ROSA. The Company has a non-operating 8.0% Project Interest, which
consists of approximately 7,689 gross (589 net) acres of leases and options in
Refugio County, Texas. A 25 square mile 3-D seismic shoot has been acquired and
interpreted. The Company believes the prospective targets are multipay Frio with
the upside of the project being the wildcat potential of the Vicksburg. Three
wells have been drilled since the Effective Date of the Acquisition Agreement
for the Company's account. One of these wells has been completed as a Frio sand
producer and is awaiting a pipeline connection, and two wells were dry holes.
The estimated cost to drill and complete a Frio sand well is approximately
$450,000.
PILEDRIVER. The Company has a 62.5% Project Interest, which consists of 640
gross (400 net) acres of leases located in Chambers County, Texas. The
objectives are two Frio sands. One of these target sands had 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 recently conducted by Western
Geophysical. The Company intends to acquire and interpret 3-D seismic data over
the project area before making any drilling decisions. The estimated cost to
drill and complete a well is approximately $1.85 million.
WILCOX CORE AREA PROJECTS
HALL RANCH. The Company has a 41.5% Project Interest, which consists of
leases and options covering approximately 8,510 gross (3,521 net) acres under a
57 square mile 3-D seismic survey in Karnes County, Texas. 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. Based upon review of
electrical logs, the Company believes this well has made a gas discovery in the
First Roeder and Migura sections of the Wilcox sands. This well was drilled at a
location in which the Company owns a 20.75% working interest. The Company owns a
41.5% working interest in the 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 Company has a 41.5% Project Interest, which contains
leases and options on approximately 6,972 gross (2,601 net) acres located in
Goliad County, Texas. The Company believes Hordes Creek has potential in the
Miocene, Frio, Yegua, and the Upper, Middle, and Lower Wilcox. Preliminary
migrated 3-D seismic data covering 25 square miles is being interpreted, and the
Company has identified five potential drilling locations. The Company currently
is attempting to delineate additional
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prospect leads from this data set. The Company has drilled two wells in the
project, both of which were dry holes. The estimated cost to drill and complete
a 9,500 foot well is approximately $800,000.
MIKESKA. The Company has a 38.0% Project Interest, which consists of leases
covering approximately 7,239 gross (2,490 net) acres located in Live Oak County,
Texas. 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 31 square mile 3-D seismic survey has been shot and
the data is being interpreted. The Company has identified several drill sites. A
well has been drilled and is currently waiting to be completed in the Upper
Wilcox formation. 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 Company has a 90.0% Project Interest, which consists
of approximately 1,979 gross (1,781 net) acres of options in Duval and McMullen
Counties, Texas. The Company's immediate plans are to acquire a one year old
proprietary 3-D seismic survey and 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.
TEXAS HACKBERRY CORE AREA PROJECTS
LOX B. The Company has a 25.0% Project Interest, which consists of 11,700
gross (2,925 net) acres of leases and options in Jefferson County, Texas. 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 believes it has identified several potential prospects through the use
of seismicly 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 East Jeffco 3-D seismic surveys described below. The first
prospect will likely be drilled in mid-1998. The estimated cost to drill and
complete a Hackberry well is approximately $900,000.
WEST PORT ACRES. The Company has a 12.5% Project Interest, on which 800
gross (100 net) acres of leases in Jefferson County, Texas have been acquired
and a 21 square mile 3-D seismic survey has been conducted. 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 Company has a 50.0% Project Interest, which consists
of over 10,000 gross (5,000 net) acres of leases and options in Jefferson
County, Texas. The initial seismic interpretation has been completed and the
Company has generated several prospects, some of which are scheduled for 1998
drilling. The estimated cost to drill and complete a shallow well is
approximately $700,000, with deeper wells costing approximately $1.5 million.
EAST JEFFCO. The Company has a 50.0% Project Interest, which consists of
24,000 (12,000 net) gross acres of leases and options in Jefferson County,
Texas. The Company is participating in a 65 square mile 3-D seismic survey that
is currently being shot, with Hackberry sands being the primary target. The
Company believes additional potential exists in the shallow Frio and deeper
Vicksburg formations. The estimated cost to drill and complete a Hackberry well
ranges from approximately $1.0 million to $1.5 million.
WEST BEAUMONT. The Company has a 6.25% Project Interest, which consists of
11,200 gross (700 net) acres of leases and options in Jefferson County, Texas. A
22.5 square mile 3-D seismic survey has been received and will be interpreted by
the Company. The estimated cost to drill and complete a Hackberry well is
approximately $1.3 million.
44
<PAGE>
LOUISIANA PROJECTS
STARBOARD. The Company has working interests in the leases over this
project ranging from 12.0% to 48.0%, depending upon the target formation depths.
A project consists of 6,682 gross (5,905 net) acres of leases in the Lapeyrouse
Field in Terrebonne Parish, Louisiana. The Company's partners include Fina Oil
and Chemical Company, two affiliates of public utilities, and a development
drilling financing commitment from Bank of America Illinois. The 3-D seismic
data has been shot, processed and interpreted. The project includes both
developmental and exploratory locations. After seismic interpretation, three
initial wells have been proposed, two of which are exploratory and one of which
is developmental. Drilling is expected to commence in the third quarter of 1998.
The estimated cost to drill and complete a well is approximately $4.4 million to
$7.5 million depending upon depth.
TACK. The Company has a 75.0% project interest which consists of 480 gross
(300 net) acres of leases in Cameron Parish, Louisiana. The primary target
objectives are in the Miocene series of sands. The Company is currently
interpreting a full fold, 12 square mile 3-D seismic shoot. The estimated cost
to drill and complete a well is approximately $1.3 million.
OTHER TEXAS PROJECTS
WILLACY COUNTY. The Company has a 78.875% Project Interest, which consists
of approximately 11,485 gross (8,784 net) acres of leases and options in Willacy
County, Texas. This project includes separate geologic structures known by four
different field names. The pre 3-D seismic geologic study of this area has
identified six possible drilling locations. These locations were selected based
on subsurface well correlation and production analysis. A 50 square mile 3-D
seismic survey is scheduled to be shot in the third quarter of 1998. Two of the
locations in the project have been drilled. Both have logged multiple pay zones
and both are awaiting completion.The estimated cost to drill and complete a well
is approximately $550,000.
CANEY CREEK. The Company has a 12.5% Project Interest, which consists of
options and leases covering 21,000 gross (2,625 net) acres in Matagorda and
Wharton Counties, Texas. 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 is currently being conducted. The estimated cost to drill and complete a
shallow well is approximately $700,000, with deeper wells costing approximately
$2.0 million.
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.
MISSISSIPPI PROJECTS
THOMPSON CREEK. The Company has a 56.0% Project Interest, which consists of
approximately 1,325 gross (512 net) acres of leases and options in Wayne County,
Mississippi. The Company has generated a prospect from subsurface and 2-D
seismic data indicating multiple potential oil pays ranging from 7,000 feet to
17,000 feet in depth. However, the Company intends to acquire and interpret 3-D
seismic data before commencing drilling. Approximately 12 square miles of full
fold 3-D seismic data will be necessary to image the acreage position. A 3-D
seismic survey is being conducted by a seismic vendor over this area and the
processed data should be delivered in the third quarter of 1998. The estimated
cost to drill and complete a 15,500 foot Cotton Valley well is approximately
$1.5 million.
45
<PAGE>
LIPSMACKER. The Company has a 22.0% Project Interest, which consists of
approximately 5,758 gross (943 net) acres of leases and options in Choctaw,
Alabama and Clarke Counties, Mississippi. EPC 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 are
two remaining drillable locations. The Company is currently evaluating whether
it will invest its own capital in drilling these wells. 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 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 that
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 30 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
46
<PAGE>
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 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) exploitation;
(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 and whether the
acquisition will improve the operations of other acquired properties. 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 deemphasized 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.
In September 1996, the Company completed the sale of its N.E. Cedardale
field in Major County Oklahoma to OXY USA, Inc., for consideration totaling
$3,550,000. The properties sold represented a substantial portion of the
Company's Oklahoma production. The divestiture of the Oklahoma properties
further facilitated the Company's focus of its resources on its Gulf Coast
projects and reduced debt service requirements over the next three years in an
amount greater than the anticipated net revenue from the properties sold. The
sale included cash of $2,840,000 and certain exchange properties that were
concurrently sold to a third party for $710,000, netting the Company $3,550,000.
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 1996, the Company, as required by the Bank
Credit Agreement, entered into a swap agreement on 62,500 MMBtu of its monthly
Mid-Continent natural gas production for $1.566 per MMBtu for the period
beginning April 1, 1996 and ending January 31, 1999. The swap, which is the
Company's only current hedge, was reduced to 31,250 MMBtu on September 25, 1996,
in connection with the sale of the N.E. Cedardale field. The Company recorded a
loss of $212,000 on this swap reduction. The Company's net gas production
currently is less then the volumes hedged. As of March 31, 1998 the Company had
an accrued liability of $179,947 to recognize the projected loss from the
hedges. The Company has not recently conducted an active hedging program other
than as required by the Credit Agreement. In that regard, the Company had net
losses of $814,029 in 1996, which includes the $212,000 loss on the swap
reductions, and $375,410 in 1997 on its required hedged positions.
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 1996 or 1997. The Company does not believe the loss
of any existing purchaser would have a material adverse effect on the Company.
47
<PAGE>
In December 1991, the Company entered into and performed under a seven-year
fixed price contract with an industrial end-user, Waldorf Corporation, for the
delivery of 7.1 Bcf of natural gas. The contract included certain prepayments to
the Company. The agreement was satisfied in January 1996 when the Company
entered into an agreement with Waldorf to terminate the agreement as of January
31, 1996. The Company paid Waldorf $2,181,489, which represents a return of
Waldorf's advance on 2,490,103 MMBTU's of natural gas, plus a settlement payment
of $313,912. The Company has been able to sell all natural gas production to
other sources at equal or higher prices since the termination of the contract.
The Company anticipates that it will be able to continue to sell all available
natural gas production in the foreseeable future.
The lender under the Duke Credit Facility has the right to gather, process,
transport and market, at competitive market rates, natural gas produced from a
majority of the projects the Company acquired pursuant to the Acquisitions until
the earlier to occur of five years from the date of the Duke Credit Facility or
until the lender has marketed 100 Bcf of natural gas under the Duke Credit
Facility.
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. Before
the Acquisitions, the Company owned interests in six wells it operates and also
owned non-operated interests in approximately 27 producing wells in Oklahoma,
Louisiana and Texas. Daily production from both operated and non-operated wells
net to the Company's interest averaged 332.34 Mcf per day and 19.96 Bbls of oil
per day for the year ended December 31, 1997. These properties have provided the
Company's revenues to date. Pursuant to the Acquisitions, the Company acquired
interests in ten wells that are complete or being completed, nine of which are
being operated by the Company. Initial production rates are not available on
these wells.
GAS AND OIL RESERVES
Set forth below is certain information concerning the Company's net proved
reserves, projected future production, estimated future net revenue from proved
reserves and the present value of such estimated net revenue as of the dates set
forth below. The Company has not obtained a report of an independent petroleum
engineer with respect to the reserve estimates set forth below. The estimates do
not include any amounts for reserves on interests acquired pursuant to the
Acquisitions. The estimates were based upon a review of production histories and
other geologic, economic, ownership and engineering data. In determining the
estimates of the reserve quantities that are economically recoverable, the
Company used selling prices and estimated development and production costs in
effect as of the dates of such estimates and, where no prior sales existed,
selling prices and production costs of comparable wells in the general area were
used. In accordance with guidelines promulgated by the Commission, no price or
cost escalation or deescalation was considered.
ESTIMATED PROVED RESERVES. The following table sets forth summary
information regarding the Company's gas and oil reserves at December 31, 1997.
<TABLE>
<CAPTION>
GAS
GAS OIL EQUIVALENT
(MCF) (BBL) (MCFE)(1)
---------- --------- ----------
<S> <C> <C> <C>
Proved developed reserves................................ 521,345 24,358 667,493
Proved undeveloped reserves.............................. 4,979,018 90,041 5,519,264
Total proved reserves.................................. 5,500,363 114,399 6,186,757
</TABLE>
- ------------------------
(1) Oil production is converted to Mcfe at the rate of six Mcf of natural gas
per Bbl of oil, based upon the approximate energy content of natural gas
and oil.
48
<PAGE>
ESTIMATE OF FUTURE NET REVENUE FROM PROVED RESERVES. The following table
sets forth summary information regarding estimated future net revenue and the
present value of future net revenue from the Company's net proved reserves as of
December 31, 1997.
<TABLE>
<CAPTION>
DECEMBER 31,
1997
------------
<S> <C>
Estimated total future net revenue (1).......................................... $8,283,153
Present value of future net revenue (2)......................................... $4,025,657
</TABLE>
- ------------------------
(1) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and future development costs, using prices and costs in effect as
of the date indicated. The amounts shown do not give effect to non-property
related expenses, such as general and administrative expenses, debt service
and future income tax expense or to depreciation, depletion and
amortization.
(2) Present value is calculated by discounting estimated future net revenue by
10% annually.
DRILLING ACTIVITY
The Company drilled only one well in each of 1991, 1992 and 1993, and each
of such wells was productive. In 1994, the Company drilled five exploratory
wells, of which four were productive, and one developmental well, which was not
productive. In 1995, the Company drilled seven exploratory wells of which four
were productive. In 1996, the Company participated in the drilling of four wells
of which two were productive. 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. Since November 1, 1997 (the
effective date of the Acquisitions) through the date hereof, 15 wells have been
drilled for the Company's account, of which six have been completed, four are
awaiting completion and five were dry holes.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the Company's
ownership as of
December 31, 1997 of productive gas and oil wells in the areas indicated.
<TABLE>
<CAPTION>
GAS OIL
---------------------- ----------------------
GROSS NET GROSS NET
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Oklahoma........................................................ 5 .04 8 .20
Texas........................................................... 1 0.07 5 2.22
Louisiana....................................................... 2 0.79 -- --
Kansas.......................................................... 1 0.10 -- --
- --
--- ---
Total......................................................... 9 1.00 13 2.42
- --
- --
--- ---
--- ---
</TABLE>
49
<PAGE>
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, average prices received and average production costs associated with
the Company's sale of gas and oil for the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------------------
1996 1997
------------ ----------
<S> <C> <C>
Net Production:
Oil (Bbl)....................................................... 9,276 7,286
Gas (Mcf)....................................................... 1,406,016 121,304
Gas equivalent (Mcfe)........................................... 1,461,672 165,020
Average sales price:
Oil ($per Bbl).................................................. $ 20.99 $ 20.28
Gas ($per Mcf).................................................. $ 2.18 $ 2.06
Average production expenses and taxes
($per Mcfe)(1)................................................ $ 0.78 $ 2.13
</TABLE>
- ------------------------
(1) Includes $164,792 in costs associated with fulfillment of contractual
transportation obligations on the Company's Mobil Bay Properties. If this
amount were not included, the average production taxes and excess for Mcfe
would have been $1.13.
LEASEHOLD ACREAGE
The following table sets forth as of December 31, 1997, 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. The information set forth below does
not include the acreage acquired in the Acquisitions.
<TABLE>
<CAPTION>
PROVED UNDEVELOPED
PROVED DEVELOPED
-------------------- --------------------
STATE GROSS NET GROSS NET
- -------------------------------------------------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oklahoma................................................ 38,606 14,091 1,370 452
Texas................................................... 10,742 1,999 54 54
Alabama................................................. 5,156 4,877 5,710 1,805
Arkansas................................................ 1,672 357 6,360 2,544
Louisiana............................................... 1,474 449 4,075 3,397
Kansas.................................................. 1,600 126 -- --
--------- --------- --------- ---------
Total............................................. 59,250 21,899 17,569 8,252
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
50
<PAGE>
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 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.
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
51
<PAGE>
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 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
52
<PAGE>
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 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.
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<PAGE>
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 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.
54
<PAGE>
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.
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 a mortgage on
virtually all remaining producing gas and oil properties to secure repayment
under the Bank Credit Agreement.
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
55
<PAGE>
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 obtaining coverage may impair the Company's ability to engage in
its business activities.
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 13,280 square feet of office space in
Corpus Christi, Texas. The monthly rent is $11,287, and the lease expires on
June 30, 2003. The Company believes it will be able to renew the lease on
acceptable terms. The Company currently is leasing more office space than it
needs in Houston, and intends to sublet a portion of its office space in 1998.
EMPLOYEES
The Company has five full-time and one part-time employees in its Houston,
Texas office, and 26 employees in its Corpus Christi, Texas office. Their
functions include management, production, engineering, geology, 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.
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 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 and EPC intend to vigorously defend the claims.
56
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information regarding the Company's
directors and executive officers.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ------------------------------ --- -------------------------------------------------
<S> <C> <C>
David W. Berry(1)............. 48 Chairman of the Board
Alex M. Cranberg(1)(2)........ 43 Vice Chairman of the Board
Michael E. Johnson(1)......... 50 Director, President and Chief Executive Officer
Charles J. Smith(1)........... 71 Director
Alex B. Campbell(3)........... 40 Director
William D. Dodge, III(2)...... 45 Director
Jack P. Randall(2)(3)......... 48 Director
Hobart A. Smith(3)............ 61 Director
David B. Christofferson....... 49 Senior Vice President, Secretary and General
Counsel
</TABLE>
- ------------------------
(1) Member of the Executive Committee.
(2) Member of the Audit Committee.
(3) Member of the Compensation Committee.
DAVID W. BERRY has served as President of the Company since the
incorporation of its predecessor in August 1988, and has served as Chairman of
the Board of Directors since 1991. In 1978, he formed Berry Petroleum
Corporation, which was a regional natural gas and oil exploration company. In
1976 he co-founded Vulcan Energy Corporation, a Tulsa, Oklahoma based
exploration and production company. Mr. Berry has served as the State Finance
Chairman of the Oklahoma State Republican Party, as a Trustee for the Oklahoma
Museum of Art and on the United States Senatorial Trust Committee. Mr. Berry is
a member of the Texas Independent Producers and Royalty Owners Association.
ALEX M. CRANBERG has been a director of the Company since May 14, 1998. He
has been President of Aspect Management Corporation, the manager of Aspect,
since its inception in 1993. He joined Houston Oil and Minerals Corp. in 1977
where he served in various engineering and financial roles. He has managed the
oil and gas portfolio of General Atlantic Partners, a private investment firm,
since 1981. He is on the Board of Directors of Brigham Exploration, Inc., a
public company, and Westport Oil and Gas, Inc., a private exploration and
production company active in the Rocky Mountain and Gulf Coast Regions. He
received a BS in petroleum engineering from the University of Texas and an MBA
from Stanford University.
MICHAEL E. JOHNSON has been a director, President and Chief Executive
Officer of the Company since May 14, 1998. He was President of EPC from 1978
until joining the Company. Mr. Johnson was an operations engineer for Atlantic
Richfield Co. from 1971 to 1976 and worked for Tana Oil and Gas before
co-founding EPC, where he has managed all exploration activities, coordinated
outside technical support and raised capital from industry partners. He received
a BS degree in mechanical engineering from the University of Southwestern
Louisiana.
CHARLES J. SMITH has been a director of the Company since May 14, 1998. He
has served as Chairman and Chief Executive Officer of EPC since its formation in
1978. Mr. Smith acts as EPC's senior land and administrative officer. He was a
practicing attorney specializing in oil and gas law from 1963 to 1987. Before
1963, he was a petroleum landman for Humble Oil and Refining Company. Mr. Smith
received a BBA in industrial management from the University of Texas and was
admitted to practice law in Texas in 1959 after attending South Texas School of
Law and the completion of off-campus studies.
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<PAGE>
ALEX B. CAMPBELL has been a director of the Company since May 14, 1998. He
has been Vice President of Aspect Management Corporation since August 1996 and
is responsible for land and corporate development and legal issues. He served as
landman for Grynberg Petroleum and TXO Production Corp. from 1980 to 1984,
focusing on the Rocky Mountain Region, then as division landman for Lario Oil &
Gas Company from 1984 to 1996, where he was responsible for administration,
prospect marketing, contract lease negotiation, exploration permitting, surface
owner negotiations and property acquisition negotiation and due diligence. He
has a BA in business/pre-law from Colorado State University, and an MBA from
Colorado State University.
WILLIAM D. DODGE, III has been a director of the Company since May 14, 1998.
He has been Regional President of Pacific Southwest Bank, Corpus Christi, Texas
since 1995. He has been active in banking since 1977, including serving as
President of The Bank of Robstown, Texas from 1982 until 1995. He also serves in
a number of civic roles, including as Chairman of the Port of Corpus Christi
Authority, and serving on the Board of Directors of Columbia Northwest Hospital.
Mr. Dodge is a member of the Editorial Review Board SAM Advanced Management
Journal at the Texas A&M University-Corpus Christi College of Business. He
received a BA degree from the University of Texas at Austin and attended the
Southwestern Graduate School of Banking, Southern Methodist University.
JACK P. RANDALL has been a director of the Company since May 14, 1998. He
founded Randall & Dewey, Inc. in 1989 and has served as its President since that
time. Randall & Dewey is a Houston, Texas, based transaction advisory firm
focusing on oil and gas mergers, acquisitions, divestments, trades and
alliances. Before founding Randall & Dewey, he was with Amoco Production Company
from 1975 to 1989, where his service included acting as Manager of Acquisitions
and Investments. Mr. Randall is a member of the Board of Directors of
Crosstimbers Oil Company, the chairman of the Petroleum Engineering Visiting
Committee at the University of Texas at Austin, and a member of the
Implementation Advisory Committee for the Oil Recovery Center of Excellence at
the University of Texas at Austin. He also is a member of the Society for
Petroleum Engineers, the American Petroleum Institute and the Independent
Petroleum Association of America. He received BS and MS degrees in engineering
from the University of Texas.
HOBART A. SMITH has been a director of the Company since May 14, 1998. He
has served as a director of Harken Energy Corporation since 1997 and a
consultant to Smith International, Inc. since 1991. From 1987 to 1991, Mr. Smith
was Vice President of Customer Relations for Smith International, Inc. From 1965
to 1987, he held numerous positions, including many executive offices with Smith
Tool, Inc., a subsidiary of Smith International, Inc. Mr. Smith has more than 30
years of experience in the oil services industry. Mr. Smith received a BA from
Claremont McKenna College.
DAVID B. CHRISTOFFERSON joined the Company in 1989 and served as a director
until May 14, 1998. Mr. Christofferson currently is Senior Vice President,
Secretary and General Counsel of the Company. He also serves as its Principal
Financial Officer. Mr. Christofferson has been active in the natural gas and oil
industry for over 20 years. He also served as General Counsel to two independent
natural gas and oil companies and to a natural gas marketing company. Mr.
Christofferson is a member of the Texas Independent Producers and Royalty Owners
Association. He received a BBA in finance and a Juris Doctor from the University
of Oklahoma. He also received a Masters of Divinity degree from Phillips
University. He is admitted to practice law in Oklahoma.
KEY OFFICERS
In addition to the directors and executive officers listed above, the
following former EPC employees have significant responsibilities with the
Company.
HOWARD E. WILLIAMS, 55, is Vice President and Treasurer. Mr. Williams joined
EPC in 1981 and became the Company's Principal Accounting Officer on May 14,
1998. He is responsible for supervising and coordinating all of the Company's
accounting activities. Before joining EPC, Mr. Williams practiced public
accounting for 17 years with "Big 8," regional and local accounting firms. Mr.
Williams is a graduate of Texas A&I University with a BBA in Accounting.
58
<PAGE>
LINDA D. SCHIBI, 41, is Vice President-Land. Mrs. Schibi joined EPC in 1978
and became the Company's Land Manager in charge of the day-to-day land
operations on May 14, 1998. She coordinates the activities of outside landmen
and supervises in-house land department operations. Mrs. Schibi also functions
as oil and gas marketing manager with responsibility for the marketing of the
Company's operated oil and gas properties. She is a Certified Petroleum Landman.
She attended Del Mar College.
DALE W. ALEXANDER, 42, is Vice President-Exploitation. He served EPC as a
consultant in the area of reservoir and exploitation engineering from 1991 until
May 14, 1998, when he became the Company's Vice President--Exploration. Mr.
Alexander is responsible for determining pre-drill economics, risk weighting
drilling projects and coordination of reserve reports. From 1988 to 1991, he was
with Kamlock Oil & Gas Company. He was an exploitation/reservoir engineer for
EPC from 1983 to 1988. He also has worked for Champlin Petroleum Company, and
Union Oil of California. Mr. Alexander has a BS in Petroleum Engineering from
the University of Texas.
MICHAEL E. MOORE, 40, is Vice President-Exploration. Mr. Moore joined EPC in
1982 as a staff geologist and became the Company's Exploration Manager on May
14, 1998. Mr. Moore is responsible for reviewing all outside geological projects
as well as supervising the activities of in-house and retainer geological staff.
He previously was employed as a field geologist with J.R. Weber, Inc., a
consulting firm in Denver, Colorado. He received a BS in Geology from the
University of Texas.
WILLIAM L. JACKSON, 42, is Senior Vice President-Operations. Mr. Jackson
joined EPC in 1982 and, on May 14, 1998, became the Company's Chief Engineering
Officer responsible for all oil and gas drilling, completion, workover, and
production operations. He previously served with Acock Engineering and Mueller
Engineering as an on-site petroleum engineering consultant on drilling and
workovers for oil and gas wells in the South Texas area. He received a BS in
Petroleum Engineering and an MBA from the University of Texas.
59
<PAGE>
EXECUTIVE COMPENSATION
The following table sets forth the compensation, including bonuses, paid by
the Company during each of the three fiscal years ended December 31, 1995, 1996
and 1997 to the Chief Executive Officer and to its other executive officers
(other than the Chief Executive Officer) of the Company and its subsidiaries.
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
AWARDS
----------------------------------
AWARDS OF ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS(1) COMPENSATION
- --------------------------------------------------- --------- ---------- --------- ------------ --------------------
<S> <C> <C> <C> <C> <C> <C>
David W. Berry..................................... 1997 $ 134,400 -- 32,000(2) $ 44,965 (3)
Chairman of the Board, 1996 124,000 -- 20,000(2) 20,145 (3)
Chief Executive Officer 1995 120,000 -- -- 18,367 (3)
and President
David B. Christofferson............................ 1997 $ 112,000 -- 58,667(2) $ 47,888 (4)
Director, Executive Vice 1996 103,000 -- 16,667(2) 22,469 (4)
President, Chief Financial 1995 85,000 5,000 -- 20,080 (4)
Officer and Secretary
S. Gordon Reese, Jr. (5)........................... 1997 $ 100,000 -- -- $ 6,553 --
Senior Vice President 1996 98,900 -- 16,250 -- --
1995 70,000 35,000 -- -- --
Michael A. Barnes(6)............................... 1997 $ 100,000 -- 4,167 -- --
Vice President of 1996 61,750 -- 4,167 -- --
Exploration and 1995 -- -- -- -- --
Production
</TABLE>
- ------------------------
(1) Represents the number of shares issuable pursuant to vested and non-vested
stock options after giving effect to the Reverse Split.
(2) In 1997 all stock options previously granted to Mr. Berry and Mr.
Christofferson were canceled and new stock options were granted to them
pursuant to the Employee Option Plan--1997 (the "1997 Plan"). Amounts stated
for 1997 include regrants of such canceled options. See "--Option
Repricings" and "--Employment Agreements."
(3) In 1997, the Company settled its deferred compensation liability to Mr.
Berry for a payment of $80,537. Of this amount, a total of $56,063 had been
reported as earned compensation in the years 1993-96, and the balance of
$24,474 is reported as earned in 1997.
(4) In 1997, the Company settled its deferred compensation liability to Mr.
Christofferson for a payment of $95,170. Of this amount, a total of $72,694
had been reported as earned compensation in the years 1993-96, and the
balance of $22,476 is reported as earned in 1997. See "--Deferred
Compensation."
(5) Mr. Reese ceased to be an officer of the Company on December 31, 1997.
(6) Mr. Barnes ceased to be an officer of the Company upon consummation of the
Acquisitions.
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<PAGE>
OPTION GRANTS
The following table sets forth certain information relating to option grants
made in 1997 to the individuals named in the Summary Compensation Table above.
See "--Executive Compensation."
<TABLE>
<CAPTION>
POTENTIAL
INDIVIDUAL GRANTS REALIZABLE
--------------------------------------------------- VALUE AT ASSUMED
% OF TOTAL ANNUAL RATES OF
OPTIONS STOCK
NUMBER OF GRANTED TO PRICE APPRECIATION MARKET
SECURITIES OF EMPLOYEES FOR PRICE
UNDERLYING IN FISCAL EXERCISE OPTION TERM(3) ON
OPTIONS 1997 PRICE PER EXPIRATION ------------------ GRANT
NAME GRANTED(1) YEAR(2) SHARE(1) DATE 5% 10% DATE
- ---------------------------------------- ------------- ---------- --------- ---------- -------- -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
David W. Berry.......................... 32,000(4) 30% $3.78 11/07 $136,000 $316,000 $ 95,040(8)
David B. Christofferson................. 58,667(4) 54% $3.78 11/07 $249,920 $580,820 $ 174,240(8)
S. Gordon Reese, Jr.(5)................. -- -- -- -- -- -- --
Michael A. Barnes(6).................... 4,167(7) 4% $7.68 4/07 $ 1,500 $ 25,000 $ 17,250
</TABLE>
- ------------------------
(1) After giving effect to the Reverse Split.
(2) Based on options to purchase a total of 107,667 shares of Common Stock
(after giving effect to the Reverse Split) granted during 1997, of which
7,500 (or 7%) have expired.
(3) Potential values stated are the result of using the Commission's method of
calculating 5% and 10% appreciation in value from the date of grant to the
end of the option term. Such assumed rates of appreciation and potential
realizable values are not necessarily indicative of the appreciation, if
any, that may be realized in future periods.
(4) Consists of options issued under the 1997 Plan, all of which are currently
exercisable. Such options were issued in 1997 in replacement of certain
options and stock appreciation rights issued in previous years. See
"--Option Repricings."
(5) Mr. Reese ceased to be an executive officer of the Company on December 31,
1997.
(6) Mr. Barnes ceased to be an officer of the Company upon consummation of the
Acquisitions.
(7) All options were granted under the 1997 Plan. One-third of the options are
currently exercisable and the remaining two-thirds become exercisable over
1998 and 1999.
(8) See "--Option Repricings."
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<PAGE>
OPTION REPRICINGS
In the last quarter of 1997, the Company determined to attempt to consummate
a significant corporate transaction 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 Acquisition
Agreement qualified as such a transaction, and their existing 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 outside
directors, 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 on
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 0.65. 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 tradeable and the discount was appropriate to reflect the actual
fair market value of the illiquid 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."
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES
OF
UNDERLYING
OPTIONS / MARKET PRICE OF
SARS STOCK AT TIME OF EXERCISE PRICE AT NEW
REPRICED OR REPRICING OR TIME OF REPRICING EXERCISE
NAME DATE AMENDED(1) AMENDMENT(1) OR AMENDMENT(1) PRICE(1)
- --------------------------------------- --------- ----------- ----------------- ----------------- -----------
<S> <C> <C> <C> <C> <C>
David W. Berry......................... 12/3/97 20,000(2) $ 5.82 $ 9.72 $ 3.78
President and Chief Executive Officer 12/3/97 4,000(3) $ 5.82 $ 18.60 $ 3.78
David B. Christofferson................ 12/3/97 30,000(4) $ 5.82 $ 10.08 $ 3.78
Executive Vice President, General 12/3/97 4,000(3) $ 5.82 $ 18.60 $ 3.78
Counsel and Secretary 12/3/97 16,667(2) $ 5.82 $ 8.82 $ 3.78
<CAPTION>
LENGTH OF
ORIGINAL OPTION
TERM REMAINING AT
DATE OF REPRICING
OR AMENDMENT
NAME (MONTHS)
- --------------------------------------- -----------------
<S> <C>
David W. Berry......................... 102
President and Chief Executive Officer 69
David B. Christofferson................ 62
Executive Vice President, General 69
Counsel and Secretary 102
</TABLE>
- --------------------------
(1) After giving effect to the Reverse Split.
(2) Consists of options to purchase shares of Common Stock pursuant to the 1996
Plan.
(3) Consists of units, each of which included an option to purchase one share of
Common Stock and a stock appreciation right ("SAR") equal to two times the
difference between the exercise price of the option and the
62
<PAGE>
market value of the SAR at the date of exercise, so that one unit had the
value of three options, all issued pursuant to the 1993 MISP.
(4) Consists of options to purchase 30,000 shares of Common Stock (after giving
effect to the Reverse Split) pursuant to the Company's 1993 Incentive Stock
Option Plan.
OPTION EXERCISE AND YEAR-END VALUES
The following table sets forth certain information as of December 31, 1997
with respect to the unexercised options to purchase Common Stock to the
individuals named in the Summary Compensation Table above. See "--Executive
Compensation." None of such individuals exercised any stock options during 1997.
<TABLE>
<CAPTION>
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED IN-THE
MONEY-OPTIONS AT DECEMBER
OPTIONS AT DECEMBER 31, 1997 31, 1997(1)
---------------------------- ----------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- --------------------------------------------------------- ----------- --------------- ----------- ---------------
<S> <C> <C> <C> <C>
David W. Berry........................................... 32,000 -- $ 28,992 --
David B. Christofferson.................................. 58,667 -- $ 53,192 --
S. Gordon Reese, Jr...................................... -- -- -- --
Michael A. Barnes........................................ 1,389 2,778 -- --
</TABLE>
- ------------------------
(1) Based on the last sale price of the Common Stock on the Nasdaq Small-Cap
Market on December 31, 1997 of $4.68 (as adjusted for the Reverse Split).
DEFERRED COMPENSATION
Pursuant to employment agreements with Messrs. Berry, Orgill and
Christofferson, deferred compensation accrued annually payable at the rate of
$9,000 per year for each year the executive was employed by the Company. The
payment of such compensation is deferred until retirement at which time it is
payable for a period of 15 years. In lieu of receiving such deferred
compensation upon retirement, in 1997 the Company paid Mr. Berry $80,537 and Mr.
Christofferson $95,170, which amounts were based upon a present value
calculation of the deferred compensation accrued as of August 30, 1997.
OPTION PLANS
MANAGEMENT INCENTIVE STOCK PLAN--1993. The MISP-1993 authorized the
issuance of up to 40,000 units (after giving effect to the Reverse Split). Each
unit consists 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 is equal to twice the amount
by which the fair market value of the Common Stock on the date of exercise of
the option exceeds the exercise price. Currently, all units have expired or have
been canceled by the Board of Directors other than 6,000 units currently
outstanding, all of which expire by August 1998.
STOCK INCENTIVE OPTION PLAN--1996. The 1996 Plan authorized the issuance of
up to 58,334 options (after giving effect to the Reverse Split) to purchase one
share of Common Stock. Currently, all options have expired or have been canceled
by the Board of Directors other than 9,500 options currently outstanding, all of
which expire by August 1998.
EMPLOYEE OPTION PLAN--1997. The 1997 Plan authorizes the issuance of up to
115,892 options (after giving effect to the Reverse Split) to purchase one share
of Common Stock. Options to purchase 96,000 shares are currently outstanding.
63
<PAGE>
The Company has agreed that for so long as the Common Stock is listed for
trading on the Boston Stock Exchange, exercise price of all future stock options
will be at least 85% of the fair market value of the Company's Common Stock on
the date of grant.
In addition, the Company intends to implement a new employee stock option
plan in which all of the Company's employees will be eligible to participate.
Shares issuable under such plan are not anticipated to exceed 5.0% of the issued
and outstanding shares of Common Stock after the Offering, however, the terms of
such plan have not be finalized.
PRINCIPAL STOCKHOLDERS
The following table sets forth certain information, as of May 14, 1998, with
respect to the Common Stock owned by (i) each person known by management to own
beneficially more than 5% of the Company's outstanding Common Stock; (ii) each
of the Company's directors and executive officers; and (iii) all directors and
executive officers of the Company as a group. Unless otherwise noted, the
persons named below have sole voting and investment power with respect to such
shares.
<TABLE>
<CAPTION>
PERCENTAGE OF
OUTSTANDING
SHARES(2)(3)(4)
------------------------
NUMBER OF BEFORE AFTER
NAME OF BENEFICIAL OWNER SHARES(1) OFFERING OFFERING
- --------------------------------------------------------------------------- ---------- ----------- -----------
<S> <C> <C> <C>
Esenjay Petroleum Corporation.............................................. 5,177,760(5) 43.97% 30.87%
1100 CCNB Center South
500 North Water Street
Corpus Christi, Texas 78471
Aspect Resources LLC....................................................... 4,285,190(6) 36.37% 25.54%
511 16th Street, Suite 300
Denver, Colorado 80202
Joint Energy Development Investments II Limited Partnership................ 675,000 5.74% 4.02%
1200 17th St., Suite 2750
Denver, Colorado 80202
David W. Berry............................................................. 142,155(7) 1.20% *
Alex M. Cranberg........................................................... 4,297,090(8) 36.47% 25.60%
511 16th Street, Suite 300
Denver, Colorado 80202
Michael E. Johnson......................................................... 5,177,760(9) 43.97% 30.87%
1100 CCNB Center South
500 North Water Street
Corpus Christi, Texas 78471
Charles J. Smith........................................................... 5,177,760(9) 43.97% 30.87%
1100 CCNB Center South
500 North Water Street
Corpus Christi, Texas 78471
Alex B. Campbell........................................................... -- * *
William D. Dodge, III...................................................... -- * *
Jack P. Randall............................................................ -- * *
Hobart A. Smith............................................................ 1,667 * *
David B. Christofferson.................................................... 68,000 10) *
Directors and executive officers as a group (9 persons)(11)................ 223,722 1.90% 1.33%
</TABLE>
- ------------------------
* Less than 1%.
64
<PAGE>
(1) Includes all shares with respect to which each person, executive officer or
director who directly, through any contract, arrangement, understanding,
relationship or otherwise, has or shares the power to vote or to direct
voting of such shares or to dispose or to direct the disposition of such
shares. Includes shares that may be purchased under stock options
exercisable within 60 days.
(2) Based on 11,762,687 shares of Common Stock outstanding at May 14, 1998 plus,
for each beneficial owner, those number of shares underlying exercisable
options held by each executive officer or director.
(3) Percent of class for any shareholder listed is calculated without regard to
shares of Common Stock issuable to others upon exercise of outstanding stock
options. Any shares a shareholder is deemed to own by having the right to
acquire by exercise of an option or warrant are considered to be outstanding
solely for the purpose of calculating that shareholder's ownership
percentage.
(4) Does not include any portion of an aggregate of 350,000 shares being
purchased in this Offering by certain of the Company's affiliates.
(5) Includes 12,500 shares of Common Stock issuable upon the exercise of
warrants. Does not include 165,000 shares of Common Stock anticipated to be
purchased in this Offering.
(6) Includes 18,750 shares of Common Stock issuable upon the exercise of
warrants. Does not include 165,000 shares of Common Stock anticipated to be
purchased in this Offering.
(7) Includes options to purchase 32,000 shares of Common Stock that are
currently exercisable. Does not include 20,000 shares of Common Stock
anticipated to be purchased in this Offering.
(8) Includes (i) 11,900 shares of Common Stock owned and (ii) 4,285,190 shares
of Common Stock owned by Aspect, which includes 18,750 shares issuable upon
the exercise of warrants, as to which Mr. Cranberg disclaims beneficial
ownership.
(9) Includes 5,165,260 shares of Common Stock owned, and 12,500 shares of Common
Stock issuable upon exercise of currently exercisable warrants held by, EPC,
as to which Messrs. Johnson and Smith disclaim beneficial ownership.
(10) Includes options to purchase 58,667 shares of Common Stock that are
currently exercisable. Does not include 20,000 shares of Common Stock
anticipated to be purchased in this Offering.
(11) Includes 63,250 shares issuable pursuant to options held by executive
officers and directors that are currently exercisable. Does not include any
shares as to which beneficial ownership is disclaimed.
CERTAIN TRANSACTIONS
The Company and Aspect Management Corporation, the manager of Aspect
("Aspect Management"), have entered into a Geotechnical Services Consulting
Agreement pursuant to which Aspect Management is to perform geotechnical
services for the Company in connection with certain oil and gas properties to
which both parties share an ownership interest. To the extent that Aspect
Management pays or advances costs or expenses associated with certain assets on
behalf of the Company, and to the extent Aspect Management hires independent
contractors, such costs and expenses will be billed to the Company. Aspect
Management must obtain the Company's approval to enter into any related contract
or agreement that has a cost exceeding $50,000 net to the Company. The Company
must pay Aspect Management for services rendered in an amount equal to Aspect's
employee costs, overhead costs and general and administrative costs associated
with the services rendered thereunder. The agreement terminates on May 14, 2002,
unless terminated by either party with 90 days' written notice to the other
party.
The Company and Aspect Management have entered into a Land Services
Consulting Agreement pursuant to which Aspect Management will provide certain
land-related services to the Company in connection with oil and gas properties
to which the Company and Aspect share an ownership interest. To
65
<PAGE>
the extent that Aspect Management pays or advances costs or management expenses
associated with assets, and to the extent Aspect Management hires independent
contractors, such cost and expenses will be billed to the Company. The Company
must pay Aspect Management for services rendered in an amount equal to Aspect's
employee costs, overhead costs and general and administrative costs associated
with the services rendered thereunder. The agreement will be effective until May
14, 2002, unless terminated by either party by giving the other party 90 days'
written notice.
Aspect received warrants to purchase 9,375 shares of Common Stock at an
exercise price of $3.00 per share in connection with providing financing under
the Initial Bridge Facility, and received warrants to purchase an additional
9,375 shares of Common Stock at an exercise price of $3.00 per share in
connection with guaranteeing a portion of the indebtedness under the Duke Credit
Facility. In addition, EPC received warrants to purchase an aggregate of 12,500
shares of Common Stock at an exercise price of $3.00 per share in connection
with guaranteeing a portion of the indebtedness under the Initial Bridge
Facility and under the Duke Credit Facility.
The Company and EPC have entered into an agreement pursuant to which the
Company loaned to EPC $3.0 million of the proceeds from the Duke Credit Facility
to be used for exploration activities on the Exploration Projects acquired from
EPC pursuant to the Acquisitions. EPC is required to repay such loan, plus
accrued interest, at the rate of prime plus 4.0% (12.5% as of the date hereof),
upon the payment by the Company to EPC of the first $3.0 million of
post-effective date costs incurred by EPC on exploration activities on such
Exploration Projects.
Mr. Berry and Mr. Christofferson (each an "Employee") each entered into an
Incentive Agreement and a Contract Settlement Agreement, and their employment
agreements with the Company were terminated upon the closing of the
Acquisitions. Pursuant to the Incentive Agreements and Contract Settlement
Agreements, the Company agreed that if the Company closes a significant
corporate transaction, and the Employee does not resign as an executive officer
before that time, the Company would pay an Incentive Payment of $134,000 to Mr.
Berry and $112,000 to Mr. Christofferson, as well as a Contract Settlement
Payment of $134,000 to Mr. Berry and $112,000 to Mr. Christofferson, at which
time Mr. Berry and Mr. Christofferson would be released from all further
obligations to the Company other than contractual confidentiality obligations.
Each of the Incentive Payments and the Contract Settlement Payments are in the
form of promissory notes bearing interest at the rate of 10% per year payable by
the Company to the Employees, with the principal amount being paid at a minimum
of $5,000 per month, beginning the first day of the third month after the
closing of the significant corporate transaction, and all principal and accrued
interest being due and payable upon the earlier of September 30, 1998, or the
completion of a public sale of any equity or debt securities of the Company,
whichever is earlier. Each of the employees, at their discretion, may defer
payment of up to 50% of the principal amount due until January 15, 1999. The
Contract Settlement Payments are intended to satisfy the Employees existing
employment contracts. Incentive Payments are intended to compensate the
Employees for their services in soliciting, negotiating and closing a
significant corporate transaction and not in satisfaction of any prior
obligations to the Company. The Incentive Payments are in addition to any other
obligations or payments due to the Employees, including the settlement of their
previously existing employment contracts. In addition, as an inducement to the
Employees to continue to solicit and close a change of control transaction, and
regardless of whether such a transaction occurs, all of the stock options
previously granted to the employees by the Company were canceled, and the
Company issued to each of the employees new stock options pursuant to the
Employee Option Plan. See "--Option Grants" and "--Option Repricing."
The Acquisitions constituted a significant corporate transaction pursuant to
which the Incentive Payments and Contract Settlement Payments are payable to Mr.
Berry and Mr. Christofferson. Mr. Berry and Mr. Christofferson have no further
contractual obligations to the Company other than confidentiality obligations
and any contractual arrangements they may negotiate with the Company in the
future.
66
<PAGE>
Effective May 1, 1996, Jeffrey Orgill and the Company agreed to the
termination of Mr. Orgill's employment agreement and Mr. Orgill resigned as Vice
President of Exploration and Production as of May 1, 1996. Mr. Orgill entered
into a consulting agreement with the Company effective May 1, 1996 that expired
in March 1998. Mr. Orgill was paid $10,000 per month under the terms of the
consulting agreement and the Company paid $120,000 to Mr. Orgill during 1997 for
consulting services.
The Company made advances to officers and affiliates of the Company during
1996 and 1997 of $51,143 and $48,380, respectively, and received repayments of
$18,741 and $99,216, respectively. The December 31, 1996 and 1997 receivables
include approximately $47,787 and $47,787, respectively, from an affiliated
partnership for which the Company serves as the managing general partner.
During 1996, as a part of the Company's relocation to Houston, Texas, the
Company purchased the homes of David W. Berry and David B. Christofferson, both
officers of the Company, for $191,395 and $178,000, respectively. These amounts
in each case were ascertained by averaging two independent MAI appraisals to
determine fair market value. The Company subsequently sold the homes at a sales
contract price of $176,200 and $178,000, respectively, pursuant to which sales
contracts the Company received net sales proceeds after commissions and other
selling expenses of $158,847 and $165,626, respectively.
Any future transaction between the Company and any of its directors,
officers or owners of five percent or more of the Company's then outstanding
Common Stock will be on terms no less favorable than would reasonably be
expected from an independent third party, and will be approved by a majority of
the directors who do not have an interest in the proposed transaction and who
have had access to the Company's outside legal counsel with respect to such
transaction.
DESCRIPTION OF SECURITIES
The authorized capital stock of the Company consists of 40,000,000 shares of
Common Stock and 5,000,000 shares of preferred stock, $.01 par value per share.
As of July 15, 1998, 11,762,687 shares of Common Stock were issued and
outstanding.
COMMON STOCK
The holders of Common Stock are entitled to one vote for each share on all
matters submitted to a vote of shareholders. There is no cumulative voting with
respect to the election of directors. Accordingly, holders of a majority of the
shares entitled to vote in any election of directors may elect all of the
directors standing for election. Subject to preferences that may be applicable
to any then outstanding class of preferred stock, the holders of Common Stock
are entitled to receive such dividends, if any, as may be declared by the Board
of Directors from time to time out of legally available funds. Upon liquidation,
dissolution or winding up of the Company, the holders of Common Stock are
entitled to share ratably in all assets of the Company that are legally
available for distribution, after payment of all debts and other liabilities and
subject to the prior rights of holders of any class of preferred stock then
outstanding. The holders of Common Stock have no preemptive, subscription,
redemption or conversion rights. The rights, preferences and privileges of
holders of Common Stock are subject to the rights of the holders of shares of
any series of preferred stock that the Company may issue in the future.
The Company's by-laws provide that stockholders owning an aggregate of at
least ten percent of the Company's issued and outstanding Common Stock can call
a special meeting of stockholders for any purpose.
PREFERRED STOCK
Shares of preferred stock may be issued from time to time in one or more
series with such designations, voting powers, if any, preferences and relative,
participating, optional or other special rights, and such qualifications,
limitations and restrictions thereof, as are determined by resolution of the
Board
67
<PAGE>
of Directors of the Company. The issuance of preferred stock, while providing
flexibility in connection with possible financing, acquisitions and other
corporate purposes, could, among other things, adversely affect the voting power
of holders of Common Stock and, under certain circumstances, be used as a means
of discouraging, delaying or preventing a change in control of the Company.
PROVISIONS AFFECTING CONTROL OF THE COMPANY
In addition to the control that will be vested in the existing stockholders
of the Company upon consummation of the Offering, the Company's Certificate of
Incorporation and Bylaws may affect control of the Company.
SIZE AND CLASSIFIED BOARD. The Company's Board of Directors currently
consists of eight members. However, the Company's Certificate of Incorporation
provides that the number of directors should be no less than four and no more
than fourteen, and such number may be determined from time to time under the
Bylaws or upon resolution of the Board of Directors. Directors need not be
stockholders. In case of vacancies in the Board of Directors, including
vacancies occurring by reason of an increase in the number of directors, a
majority of the remaining members of the Board, even though less than a quorum,
may elect directors to fill to such vacancies to hold office until the next
annual meeting of the stockholders or until their successors are elected and
qualify. The Company's Certificate of Incorporation also classifies the
Company's Board of Directors into three classes serving staggered, three-year
terms. Classification of the Board of Director's could have the effect of
extending the time during which the existing Board of Directors could control
the operating policies of the Company even though opposed by the holders of a
majority of the outstanding shares of the Common Stock.
REMOVAL OF DIRECTORS. Under the DGCL, a director of a corporation generally
may be removed, with or without cause, by the holders of a majority of the
shares entitled to vote at an election of directors. However, unless the
corporation's certificate of incorporation provides otherwise, if the
corporation's board of directors is classified, such as the Company's Board,
directors may be removed only for cause and only by stockholder action.
Generally, the vote for removal would require the affirmative vote of a majority
of shares entitled to vote at an election of directors. The Company intends to
propose an amendment to its Certificate of Incorporation to permit the removal
of directors with or without cause. Such proposal will be voted upon at the
Company's next annual meeting of stockholders. EPC and Aspect, who collectively
own approximately 81% of the Company's Common Stock, have informed the Company
that they intend to vote in favor of such proposal.
DELAWARE LAW PROVISIONS
The Company is a Delaware corporation and is subject to Section 203 of the
DGCL. Generally, Section 203 prohibits the Company from engaging in a "business
combination" (as defined in Section 203 of the DGCL) with an "interested
stockholder" (defined generally as a person owning 15% or more of the Company's
outstanding voting stock) for three years following the date that person becomes
an interested stockholder, unless (i) before that person became an interested
stockholder, the Company's Board of Directors either approved the transaction
which resulted in the stockholder becoming an interested stockholder or approved
the business combination; (ii) upon completion of the transaction that resulted
in the stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of the voting stock outstanding at the time the
transaction commenced (excluding stock held by directors who are also officers
of the Company and by employee stock plans that do not provide employees with
the right to determine confidentially whether shares held subject to the plan
will be tendered in a tender or exchange offer); or (iii) following the
transaction in which that person became an interested stockholder, the business
combination is approved by the Company's Board of Directors and authorized at a
meeting of stockholders by the affirmative vote of the holders of at least
two-thirds of the outstanding voting stock not owned by the interested
stockholder.
68
<PAGE>
Section 203 restrictions also do not apply to certain business combinations
proposed before the consummation or abandonment of and after the announcement or
notification of one of certain extraordinary transactions involving the Company
and a person who was either not an interested stockholder during the previous
three years or who became an interested stockholder with the approval of the
Company's Board of Directors. The extraordinary transaction must be approved or
not opposed by a majority of the Board of Directors who were directors before
any person became an interested stockholder in the previous three years or who
were recommended for election or elected to succeed such directors by a majority
of such directors then in office.
REGISTRATION RIGHTS
The Company has entered into a registration rights agreement with EPC and
Aspect with respect to the 9,368,367 shares of Common Stock they received in the
Acquisitions and the 31,250 shares of Common Stock issuable upon the exercise of
their warrants to purchase Company Stock. The agreement grants to EPC and Aspect
up to three demand and unlimited piggyback registrations. The Company has filed
a shelf registration statement with respect to all of such shares of Common
Stock. Such registration statement also covers (i) 675,000 shares of Common
Stock issued to an affiliate of Enron Corp. in the Acquisitions, (ii) 63,335
shares of Common Stock issued to certain of Aspect's employees in the
Acquisitions, (iii) 32,000 shares of Common Stock issuable upon the exercise of
stock options held by Mr. Berry and (iv) 68,000 shares of Common Stock on behalf
of Mr. Christofferson, of which 58,667 shares are issuable upon the exercise of
options.
The Company has entered into a registration rights agreement with Hi-Chicago
Trust with respect to 12,500 shares of Common Stock and 50,000 shares of Common
Stock issuable upon the exercise of a warrant. Such agreement grants to
Hi-Chicago Trust two demand and unlimited piggyback registrations. The Company
has filed a registration statement with respect to the Common Stock and the
shares issuable upon exercise of the warrant, and such registration statement
has been declared effective under the Securities Act.
The Company also has entered into a registration rights agreement with
Weisser, Johnson & Co. with respect to 250,00 shares of Common Stock and a
registration rights agreement with LaSalle Street Natural Resources Corporation
with respect to 250,000 shares of Common Stock. In addition, the Representative
has registration rights with respect to the 210,000 shares of Common Stock
issuable upon the exercise of the Representative's Warrant.
Each of these registration rights agreements contain provisions that permit
the managing underwriter in an underwritten public offering to cut back the
number of shares of Common Stock requested to be included in a piggyback
registration if the managing underwriter believes that the number of shares
requested to be included is greater than the number of shares that can be sold.
TRANSFER AGENT AND REGISTRAR
The transfer and registrar for the Common Stock is Bank One Oklahoma.
69
<PAGE>
UNDERWRITING
The Underwriters named below, for whom Gaines, Berland Inc. is acting as
representative (the "Representative"), have severally agreed to purchase from
the Company the respective number of shares of Common Stock set forth opposite
their names:
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
- ----------------------------------------------------------------------------------------------------- ----------
<S> <C>
Gaines, Berland Inc.................................................................................. 3,030,000
Bear, Stearns & Co. Inc.............................................................................. 75,000
Credit Lyonnais Securities (USA) Inc................................................................. 75,000
Jefferies & Company, Inc............................................................................. 75,000
Johnson Rice & Company L.L.C......................................................................... 75,000
Petrie Parkman & Co.................................................................................. 75,000
Schroder & Co. Inc................................................................................... 75,000
BlueStone Capital Partners, L.P...................................................................... 40,000
Chatsworth Securities LLC............................................................................ 40,000
Fahnestock & Co. Inc................................................................................. 40,000
First Southwest Company.............................................................................. 40,000
Hanifen, Imhoff Inc.................................................................................. 40,000
Hoak Breedlove Wesneski & Co......................................................................... 40,000
Ladenburg Thalmann & Co. Inc......................................................................... 40,000
Neidiger, Tucker, Bruner, Inc........................................................................ 40,000
Pennsylvania Merchant Group Ltd...................................................................... 40,000
Southeast Research Partners, Inc..................................................................... 40,000
Starr Securities, Inc................................................................................ 40,000
Van Kasper & Company................................................................................. 40,000
Wedbush Morgan Securities Inc........................................................................ 40,000
----------
Total............................................................................................ 4,000,000
----------
----------
</TABLE>
The Underwriting Agreement provides that the obligations of the several
Underwriters thereunder are subject to approval of certain legal matters by
counsel and to various other considerations. The nature of the Underwriters'
obligations is such that they are committed to purchase and pay for all of the
above shares of Common Stock if any are purchased.
The Underwriters, through the Representative, have advised the Company that
they propose to offer the Common Stock initially at the public offering price
set forth on the cover page of this Prospectus; that the Underwriters may allow
to selected dealers a concession of $0.15 per share; and that such dealers may
reallow a concession of $0.10 per share to certain other dealers. After the
public offering, the offering price and other selling terms may be changed by
the Underwriters. The Common Stock is included for quotation on the Nasdaq
Small-Cap Market.
The Company has granted to the Underwriters a 30-day over-allotment option
to purchase up to an aggregate of 600,000 additional shares of Common Stock,
exercisable at the public offering price less the underwriting discount. If the
Underwriters exercise such over-allotment option, then each of the Underwriters
will have a firm commitment, subject to certain conditions, to purchase
approximately the same percentage thereof as the number of shares of Common
Stock to be purchased by it as shown in the above table bears to the 4,000,000
shares of Common Stock offered hereby. The Underwriters may exercise such option
only to cover over-allotment made in connection with the sale of the shares of
Common Stock offered hereby.
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<PAGE>
The Company, its executive officers and directors, EPC and certain of its
affiliates, Aspect and an affiliate of Enron Corp. have agreed that they will
not sell or dispose of any shares of Common Stock for a period of 180 days (90
days in the case of Mr. Christofferson and such Enron Corp. affiliate) after the
closing of this Offering without the prior written consent of the
Representative. Notwithstanding the foregoing, under certain circumstances,
certain holders of the Common Stock subject to such restrictions on transfer may
pledge their Common Stock to secure indebtedness or transfer their Common Stock
to their affiliates (provided the pledgee or transferee agrees to become subject
to such restrictions on transfer), or may transfer their Common Stock to
charitable organizations after December 15, 1998.
In connection with the offering made hereby, the Company has agreed to sell
to the Representative, for nominal consideration, a warrant (the
"Representative's Warrant") to purchase from the Company up to 210,000 shares of
Common Stock. The Representative's Warrant is exercisable, in whole or in part,
at an exercise price of $7.20 per share at any time during the three-year period
commencing one year after the effective date of the Registration Statement of
which this Prospectus is a part. The Representative's Warrant contains
provisions providing for adjustment of the exercise price and the number and
type of securities issuable upon exercise of the Representative's Warrant should
any one or more of certain specified events occur. The Representative's Warrant
grants to the holders thereof certain rights of registration for the securities
issuable upon exercise of the Representative's Warrant.
The Representative has reserved an aggregate of 350,000 shares of Common
Stock for sale at the public offering price to Aspect, EPC and Mr. Berry. The
Representative and such persons currently anticipate that Aspect and EPC each
will purchase 165,000 of such shares, and Mr. Berry will purchase 20,000 of such
shares; however such shares may be purchased by such persons in different
proportions, or may be allocated to certain affiliates or principals of such
persons. The Underwriters and the Company have agreed that $14,000 of the
underwriting discount attributable to such shares will be reimbursed to the
Company, thereby increasing the Company's proceeds from this Offering by such
amount.
The Company has agreed to indemnify the Underwriters against certain
liabilities, losses and expenses, including liabilities under the Securities Act
or to contribute to payments that the Underwriters may be required to make in
respect thereof. The Company has agreed to pay to the Representative a
nonaccountable expense allowance of $300,000.
As permitted by Rule 103 under the Exchange Act certain Underwriters (and
selling group members, if any) that are market makers ("passive market makers")
in the Common Stock may make bids for or purchases of the Common Stock in the
Nasdaq Small-Cap Market until such time, if any, when a stabilizing bid for such
securities has been made. Rule 103 generally provides that (i) a passive market
maker's net daily bid purchase of the Common Stock may not exceed 30% of its
average daily trading volume in such securities for the two full consecutive
calender months (or any 60 consecutive days ending within the 10 days)
immediately preceeding the filing date of the registration statement of which
this Proscectus forms a part, (ii) a passive market maker may not effect
transaction or display bids for the Common Stock at a price that exceeds the
highest independent bid for the Common stock by persons who are not passive
market makers and (iii) bids made by passive market makers must be identified as
such.
The Company and the Representative entered into an engagement letter dated
December 3, 1997, pursuant to which the Representative agreed to provide
financial advisory services to the Company. In connection with such engagement,
the Representative acted as the Company's financial advisor in connection with
the Acquisitions and rendered an opinion that, subject to certain assumptions
and analyses set forth in such opinion, the consideration paid to EPC and Aspect
pursuant to the Acquisition Agreement was fair to the Company's shareholders
from a financial point of view. The Company agreed to pay the Representative
$200,000 and reimburse the Representative for $15,000 of expenses incurred
before execution of the engagement letter and to further reimburse the
Representative for additional out-of-pocket expenses reasonably incurred in
connection with its engagement, including the reasonable fees and disbursements
of the Representative's legal counsel. Such fees and expenses were for financial
advice in
71
<PAGE>
connection with the Acquisitions, including the fairness opinion related
thereto. The Company also agreed to pay the Representative a fee equal of
$200,000 upon the closing of any additional equity funding or mezzanine funding
not underwritten by the Representative in excess of $10.0 million within 18
months of the date of the engagement letter, provided the Acquisitions have been
completed. Such $200,000 fee is not payable if the Company completes an
underwritten public offering with the Representative as the underwriter within
such 18 month period. This Offering constitutes an underwritten public offering
that cancels the Company's obligations to pay such $200,000 fee.
The Representative has performed underwriting and financial advisory
services for the Company in the past and anticipates it will continue to provide
such services in the future. In connection with prior services, the
Representative was issued 67,500 shares of Common Stock and warrants to purchase
67,500 shares of the Company's Common Stock at an exercise price of $12.15 per
share.
An affiliate of the Representative participated in 37.5% of Aspect's
obligation to lend funds to the Company under the Initial Bridge Facility and
granted a limited guaranty of the Company's repayment obligations under the Duke
Credit Facility, and in exchange for such participation and guaranty, received
warrants to purchase an aggregate of 18,750 shares of Common Stock at an
exercise price of $4.00 per share. Neither these warrants nor the Common Stock
issuable upon the exercise thereof may be sold, transferred, hypothecated,
pledged or otherwise disposed of until one year from the date of this
Prospectus.
LEGAL MATTERS
Certain legal matters in connection with the Common Stock offered hereby are
being passed upon for the Company by Porter & Hedges, L.L.P., Houston, Texas.
Certain legal matters relating to this offering will be passed upon for the
Underwriter by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements at December 31, 1997 and 1996 and for
each of the two years in the period ended December 31, 1997, included in this
Prospectus have been audited by Deloitte & Touche LLP independent auditors, as
stated in their report appearing herein, and have been so included in reliance
upon such reports given upon the authority of that firm as experts in accounting
and auditing.
AVAILABLE INFORMATION
This Prospectus constitutes a part of a Registration Statement on Form SB-2
(together with all amendments and exhibits thereto, the "Registration
Statement") filed by the Company with the Commission under the Securities Act.
This Prospectus omits certain of the information contained in the Registration
Statement, and reference is hereby made to the Registration Statement for
further information with respect to the Company and the Securities offered
hereby. Any statements contained herein concerning the provisions of any
document filed as an exhibit to the Registration Statement or otherwise filed
with the Commission are not necessarily complete, and in each instance,
reference is made to the copy of such document so filed. Each such statement is
qualified in its entirety by such reference.
The Company is subject to the information requirements of the Exchange Act,
and in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information can be inspected and copied at the Public Reference Facilities
maintained by the Commission at its principal offices at 450 Fifth Street, N.W.,
Washington, D.C. 20549, and at its regional offices at 7 World Trade Center,
13th Floor, New York, New York 10048, and the Citicorp Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60661. Such information also may be
obtained on the Internet through the Commission's EDGAR database at
HTTP://WWW.SEC.GOV.
72
<PAGE>
GLOSSARY OF CERTAIN INDUSTRY TERMS
The terms used in this Prospectus are defined as set forth below. All
volumes of natural gas referred to herein are stated at the legal pressure base
of the state or area where the reserves exist and at 60 degrees Fahrenheit and,
in most instances, are rounded to the nearest major multiple.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
BBLS/D. Stock tank barrels per day.
BCF. Billion cubic feet.
BCFE. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
COMPLETION. The installation of permanent equipment for the production of
oil or gas or, in the case of a dry hole, the reporting of abandonment to the
appropriate agency.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
DRY HOLE OR WELL. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
EXPLORATORY WELL. A Well drilled to find and produce oil or gas reserves
not classified as proved, to find a new reservoir in a field previously found to
be productive of oil or gas in another reservoir or to extend a known reservoir.
FARM-IN OR FARM-OUT. An agreement whereunder the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one, or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."
FIELD. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
FINDING COSTS. Costs associated with acquiring and developing proved oil
and natural gas reserves which are capitalized by the Company pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling and
completing wells.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be,
in which a working interest is owned.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons per
day.
MCF. One thousand cubic feet of gas.
MCF/D. One thousand cubic feet of gas per day.
73
<PAGE>
MCFE. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
MMCF One million cubic feet.
MMCF/D. One million cubic feet per day.
MMCFE. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas. Prices have historically been
higher or substantially higher for crude oil than natural gas on an energy
equivalent basis.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.
NORMALLY PRESSURED RESERVOIRS. Reservoirs with a formation-fluid pressure~
equivalent to 0.465 psi per foot of depth from the surface. For example, if the
formation pressure is 4,650 psi at 10,000 feet, then the pressure is considered
to be normal.
PRESENT VALUE. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
PRODUCTIVE WELL. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED LOCATION. A site on which a development well can be
drilled consistent with-spacing rules for purposes of recovering proved
undeveloped reserves.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
RECOMPLETION. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
RESERVOIR. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
74
<PAGE>
ROYALTY INTEREST. An interest in an oil and natural gas property entitling
the owner to a share of oil or gas production free of costs of production.
3-D SEISMIC. Advanced technology method of detecting accumulations of
hydrocarbons identified through a three-dimensional picture of the subsurface
created by the collection and measurement of the intensity and timing of sound
waves transmitted into the earth as they reflect back to the surface.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
WORKOVER. Operations on a producing well to restore or increase production.
75
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
Independent Auditors' Report............................................................................... F-2
Consolidated Balance Sheets as of December 31, 1997 and 1996............................................... F-3
Consolidated Statements of Operations for the years ended December 31, 1997 and 1996....................... F-4
Consolidated Statements of Stockholders' Equity for the years ended December 31, 1997 and 1996............. F-5
Consolidated Statements of Cash Flows for the years ended December 31, 1997 and 1996....................... F-6
Notes to Consolidated Financial Statements................................................................. F-7
Condensed Consolidated Balance Sheet (unaudited) as of March 31, 1998...................................... F-24
Condensed Consolidated Statements of Operations for the three months ended March 31, 1998 and 1997
(unaudited).............................................................................................. F-25
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 1998 and 1997
(unaudited).............................................................................................. F-26
Notes to Condensed Consolidated Financial Statements (unaudited)........................................... F-27
</TABLE>
F-1
<PAGE>
ESENJAY EXPLORATION, INC.
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, 1997 and 1996 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, 1997 and 1996, and the results of their operations and their cash
flows for the years then ended in conformity with generally accepted accounting
principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 2 to the
financial statements, the Company's recurring losses from operations raise
substantial doubt about its ability to continue as a going concern. Management's
plans concerning these matters are also described in Note 2. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
Deloitte & Touche LLP
Houston, Texas
March 27, 1998(May 14, 1998 with
respect to the second
paragraph of Note 2 and
the third and fourth
paragraphs of Note 10)
F-2
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1996
------------- ------------
<S> <C> <C>
Current assets:
Cash and cash equivalents.......................................................... $ 690,576 $4,956,656
Accounts receivable, net of allowance for doubtful accounts of $15,488 at December
31, 1997 and $10,533 at December 31, 1996........................................ 221,864 366,498
Prepaid expenses and other......................................................... 249,328 282,317
Receivables from affiliates........................................................ 105,171 152,419
------------- ------------
Total current assets............................................................. 1,266,939 5,757,890
Property and equipment:
Gas and oil properties, at cost--successful efforts method of accounting........... 3,235,848 5,280,115
Other property and equipment....................................................... 1,169,127 1,074,727
------------- ------------
4,404,975 6,354,842
Less accumulated depletion, depreciation and amortization.......................... (1,260,605) (2,918,918)
------------- ------------
3,144,370 3,435,924
Other assets......................................................................... 164,699 437,378
------------- ------------
Total assets..................................................................... $ 4,576,008 $9,631,192
------------- ------------
------------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................... $ 911,396 $ 725,222
Revenue distribution payable....................................................... 68,131 360,163
Current portion of long-term debt.................................................. 401,085 304,540
Accrued and other liabilities...................................................... 299,704 208,931
------------- ------------
Total current liabilities........................................................ 1,680,316 1,598,856
Long-term debt....................................................................... 22,680 325,394
Non-recourse debt.................................................................... 864,000 681,618
Accrued interest on non-recourse debt................................................ 194,274 62,874
Other long-term liabilities.......................................................... 9,918 223,624
------------- ------------
Total liabilities................................................................ 2,771,188 2,892,366
Commitments and contingencies
Stockholders' equity:
Cumulative convertible preferred stock $.01 par value; 5,000,000 shares authorized;
85,961 shares issued and outstanding at December 31, 1997 and 1996; ($859,610
aggregate redemption and liquidation preference at December 31, 1997 and 1996)... 860 860
Common stock:
Class A Common stock, $.01 par value; 40,000,000 shares authorized; 1,655,984 and
1,644,317 outstanding at December 31, 1997 and December 31, 1996, respectively
(1)............................................................................ 16,560 16,443
Unamortized value of warrants issued............................................... (27,163) (54,325)
Common stock subscribed............................................................ -- 45,000
Common stock subscription receivable............................................... -- (45,000)
Additional paid-in capital (1)..................................................... 14,751,425 14,681,542
Accumulated deficit................................................................ (12,936,862) (7,905,694)
------------- ------------
Total stockholders' equity....................................................... 1,804,820 6,738,826
------------- ------------
Total liabilities and stockholders' equity....................................... $ 4,576,008 $9,631,192
------------- ------------
------------- ------------
</TABLE>
- --------------------------
(1) After giving effect to the 1:6 reverse stock split effected on May 14, 1998.
See Note 10.
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Revenues:
Gas and oil revenues.............................................................. $ 664,126 $ 3,176,861
Realized gain (loss) on commodity transactions.................................... (375,410) (814,029)
Unrealized loss on commodity transactions......................................... (128,936) --
Gain on sale of assets............................................................ 452,020 250,437
Operating fees.................................................................... 55,021 213,834
Other revenues.................................................................... 241,788 339,689
------------- -------------
Total revenues.................................................................. 908,609 3,166,792
------------- -------------
Costs and expenses:
Lease operating expense........................................................... 427,240 556,925
Production taxes.................................................................. 24,497 207,969
Transportation and gathering costs................................................ 143,265 368,716
Gas purchases under deferred contract............................................. -- 82,461
Depletion, depreciation and amortization.......................................... 315,880 2,237,648
Impairment of oil and gas properties.............................................. 349,384 51,000
Exploration costs................................................................. 2,258,702 1,317,161
Interest expense.................................................................. 60,942 783,872
Deferred gas contract settlement.................................................. -- 368,960
General and administrative expense................................................ 2,070,812 2,217,099
Delay rentals..................................................................... 211,690 --
------------- -------------
Total costs and expenses........................................................ 5,862,412 8,191,811
------------- -------------
Loss before provision for income taxes.............................................. (4,953,803) (5,025,019)
Benefit (provision) for income taxes................................................ -- --
------------- -------------
Net loss............................................................................ (4,953,803) (5,025,019)
Cumulative preferred stock dividend................................................. 103,153 103,153
------------- -------------
Net loss applicable to common stockholders.......................................... $ (5,056,956) $ (5,128,172)
------------- -------------
------------- -------------
Net loss per common share(1)........................................................ $ (3.07) $ (4.31)
------------- -------------
------------- -------------
Weighted average number of common shares outstanding(1)............................. 1,646,311 1,190,343
</TABLE>
- ------------------------
(1) After giving effect to the 1:6 reverse stock split effected on May 14, 1998.
See Note 10.
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
CLASS A COMMON UNAMORTIZED
PREFERRED STOCK SHARES(1) VALUE OF ADDITIONAL
------------------------ -------------------- WARRANTS PAID-IN ACCUMULATED
SHARES AMOUNT SHARES AMOUNT ISSUED CAPITAL(1) DEFICIT
----------- ----------- --------- --------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995...... 85,961 $ 860 843,067 $ 8,431 -- $ 7,909,032 $ (2,854,887)
Issuance of common stock........ -- -- 801,250 8,012 -- 6,657,010 --
Warrant issued for services..... -- -- -- -- $ (82,500) 115,500 --
Cumulative preferred stock
dividend...................... -- -- -- -- -- -- (25,788)
Amortization of warrants........ 28,175
Net loss........................ -- -- -- -- -- -- (5,025,019)
----------- ----- --------- --------- ------------ ----------- ------------
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)
----------- ----- --------- --------- ------------ ----------- ------------
----------- ----- --------- --------- ------------ ----------- ------------
</TABLE>
- ------------------------
(1) After giving effect to the 1:6 reverse stock split effected on May 14, 1998.
See Note 10.
The accommpanying notes are an integral part of these financial statements.
F-5
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss)................................................................ $ (4,953,803) $ (5,025,019)
Adjustments to reconcile net loss to net cash (used) in operating activities:
Depletion, depreciation and amortization....................................... 315,880 2,237,648
Impairment of oil and gas properties........................................... 349,384 51,000
Deferred gas contract settlement............................................... -- 368,960
Gain on sale of assets......................................................... (452,020) (250,437)
Gain on settlement of deferred compensation agreement.......................... (25,794) --
Deferred revenues under gas contract........................................... -- (74,400)
Amortization of financing costs and warrants................................... 46,128 710,573
Unrealized loss on commodity transitions....................................... 128,936 --
Exploration costs.............................................................. 2,258,702 1,317,161
Changes in operating assets and liabilities:
Trade and affliliate receivables............................................. 191,882 303,975
Prepaid expenses and other................................................... 198,418 (103,580)
Other assets................................................................. 272,679 (191,791)
Accounts payable............................................................. 186,174 (279,119)
Revenue distribution payable................................................. (292,032) (132,909)
Accrued and other............................................................ (118,936) (2,647)
------------- -------------
Net cash (used) in operating activities........................................ (1,894,402) (1,070,585)
------------- -------------
Cash flows used in investing activities:
Capital expenditures--gas and oil properties..................................... (3,023,253) (3,515,841)
Capital expenditures--other property and equipment............................... (159,679) (203,808)
Proceeds from sale of assets..................................................... 1,002,540 4,671,088
------------- -------------
Net cash provided by (used) in investing activities............................ (2,180,392) 951,439
------------- -------------
Cash flows from financing activities:
Proceeds from issuance of debt................................................... 182,382 4,717,280
Repayments of long-term debt..................................................... (296,303) (3,745,369)
Debt issuance cost............................................................... -- (183,387)
Payment for settlement of deferred gas contract.................................. -- (2,181,489)
Preferred stock dividends paid................................................... (77,365) (25,788)
Net proceeds from issuance of common stock....................................... -- 6,430,647
------------- -------------
Net cash (used) in by financing activities..................................... (191,286) 5,011,894
------------- -------------
Net increase (decrease) in cash and cash equivalents............................... (4,266,080) 4,892,748
Cash and cash equivalents at beginning of year..................................... 4,956,656 63,908
------------- -------------
Cash and cash equivalents at end of year........................................... $ 690,576 $ 4,956,656
------------- -------------
------------- -------------
Supplemental disclosure of cash flow information:
Cash paid for interest........................................................... $ 141,356 $ 818,769
------------- -------------
------------- -------------
</TABLE>
The accompanying notes are an integral part of these financial statments.
F-6
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION--The Company's primary business activities include gas
and oil exploration, production and sales, primarily in the Southwestern and
Gulf Coast areas of the United States. The accompanying consolidated financial
statements include the accounts of the Company, and its subsidiaries.
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 those estimates.
CASH EQUIVALENTS--The Company considers all investments with a maturity of
three months or less when purchased to be cash equivalents.
GAS AND OIL PROPERTIES--The Company uses the successful efforts method of
accounting for gas and oil exploration and development costs. All costs of
acquired wells, productive exploratory wells, and development wells are
capitalized. 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. Valuation
allowances are provided if the net capitalized costs of gas and oil properties
at the field level exceed their realizable values based on expected future cash
flows. Unproved properties are periodically assessed for impairment and, if
necessary, a loss is recognized by providing an allowance.
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.
Depletion is provided by the unit of production method based upon reserve
estimates. Depletion, depreciation and amortization includes approximately
$349,384 and $51,000 in 1997 and 1996, respectively, in impairment of gas and
oil properties, due to changes in reserve estimates.
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 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.
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.
F-7
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
CAPITALIZED INTEREST--The Company capitalizes interest costs incurred on
exploration projects. The interest capitalized for the years ended December 31,
1997 and 1996 was approximately $235,977 and $107,000, 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. At December 31, 1997, the Company's gas
balancing position was approximately 29,244 MCF overproduced.
EXPLORATION COSTS--The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. During
1996, $43,000 of such costs represented geological and geophysical costs
expensed as required under the successful efforts method of accounting. There
were no such costs incurred in 1997.
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.
STOCK-BASED COMPENSATION--In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 123
("SFAS 123"), "Accounting for Stock-Based Compensation." SFAS 123 establishes a
fair value method and disclosure standards for stock-based employee compensation
arrangements, such as stock purchase plans and stock options. It also applies to
transactions in which an entity issues its equity instruments to acquire goods
or services from non-employees, requiring that such transactions be accounted
for based on fair value. As allowed by SFAS 123, the Company will continue to
follow the provisions of Accounting Principles Board Opinion No. 25 ("APB") for
its stock-based employee compensation arrangements. SFAS 123 requires entities
that elect to continue to measure compensation cost using APB 25 to disclose
proforma information computed as if the fair value based accounting method of
SFAS 123 had been applied for all awards granted after December 15, 1994.
EARNINGS PER SHARE--In February 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 128 ("SFAS 128"),
"Earnings per Share" and Statement of Financial Accounting Standards No. 129
("SFAS 129"), "Disclosure of Information about Capital Structure." SFAS 128
establishes standards for computing and presenting earnings per share ("EPS")
and requires restatement of all prior-period EPS data presented. SFAS 129
establishes standards for disclosing information about an entity's capital
structure. 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 (as adjusted) by the weighted
F-8
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
average number of common shares outstanding plus dilutive potential common
shares. For the years ended December 31, 1997 and 1996 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 periods indicated, with 1996 being restated to
conform with the requirements of the Statement of Financial Accounting Standards
No. 128 Earning Per Share, described below.
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
BASIC EARNINGS PER SHARE
Weighted Average Common Shares Outstanding as Restated for the 1:6 Reverse Stock
Split Effected on May 14, 1998 (See Note 10)................................... 1,646,311 1,190,343
Basic (Loss) Per Share, as Restated.............................................. $ (3.07) $ (4.31)
------------- -------------
------------- -------------
EARNINGS FOR BASIC COMPUTATION
Net (Loss)....................................................................... $ (4,953,803) $ (5,025,019)
Preferred Share Dividends........................................................ (103,153) (103,153)
------------- -------------
Net Income (Loss) to Common Shareholders (Basic (Loss) Per Share Computation).... $ (5,056,956) $ (5,128,172)
------------- -------------
------------- -------------
</TABLE>
RECLASSIFICATION--Certain reclassifications have been made to the 1996
financial statements to conform them to the classification used in 1997.
2. GOING CONCERN:
The accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. The Company has
experienced a significant decline in operations including declines in ongoing
gas and oil production. These declines have created a significant working
capital deficit and depleted cash reserves. As a result of the declining
positions, the Company has also failed to meet its financial debt covenants
although it has secured a waiver through the earlier of the consummation of the
Acquisitions or June 1998. In the event that the Company is not able to secure
future waivers and the debt is ultimately called, the Company may not be able to
timely meet this demand.
The Company has prepared an operating budget for 1998 which projects a
negative cash flow. Such negative cash flows are expected to further deplete
existing cash balances. The Company has obtained a bridge financing arrangement
from Duke Energy Financial Services, Inc. in connection with the proposed
Acquisitions discussed in Note 10. Such Acquisition was approved by the
Company's stockholders and consummated on May 14, 1998. Nevertheless, if the
Company is unsuccessful in its attempt to secure permanent financing and/or
equity capital, the Company will be required to sell substantial interests in
its exploration projects in order to continue as a going concern. The Company is
actively pursuing various sources of permanent financing and/or equity capital.
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. See Note 10.
F-9
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. STOCKHOLDERS' EQUITY: (CONTINUED)
Effective November 12, 1993, the Company completed its initial public
offering of 350,000 Units of its securities. Each unit consisted of two (2)
shares of cumulative convertible preferred stock (valued at $10.00 per share),
one-sixth ( 1/6) share of common stock (valued at $24.00) and one-sixth ( 1/6)
warrant ("Series A Warrant") (valued at $0.60). During 1995, the Company offered
to exchange one (1) share of cumulative convertible preferred stock plus all
unpaid and accrued preferred dividends for two-third's ( 2/3) share of common
stock and two (2) Series A Warrants for a limited period. The Company concluded
its offer on May 26, 1995 with a total of 603,939 shares of convertible
preferred stock tendered. As a result of the offering, the Company issued
402,626 shares of Common Stock and 201,313 Series A Warrants. After May 26,
1995, the exchange ratio reverted to the original conversion terms. The Company
reflected the market value of the additional one-third ( 1/3)share of common
stock paid as a one-time premium to induce conversion of the cumulative
convertible preferred stock as an addition to net loss in computing loss
applicable to common shareholders in the amount of $2,415,756. The Company was
relieved of $232,285 of accrued dividends relating to the shares tendered, which
has been offset against the inducement premium. As of December 31, 1997 and
1996, 85,961 shares of cumulative convertible preferred stock were outstanding.
In connection with the debt financing obtained during the first quarter of
1996, the Company, pursuant to an agreement with a financial advisor, agreed to
pay a combination of cash, stock and warrants (See--"Warrants") in consideration
for assisting with obtaining the financing. The Company paid $200,000 in cash
and issued 25,000 shares of the Company's common stock to the advisor on June 6,
1996. These shares have been valued at $234,375, the fair market value at the
date granted.
On August 14, 1996, the Company closed the sale of a public offering of
1,350,000 Units of its securities. Subsequently, the Company sold an additional
over all allotment of 202,500 Units. Each Unit consisted of one-half ( 1/2)
share of Common Stock and one-half ( 1/2) Series B Redeemable Common Stock
Purchase Warrant ("Series B Warrants"). The price for each Unit was $30.375. The
net proceeds, after underwriter's commission and expenses, was approximately
$6,431,000.
CONVERTIBLE PREFERRED STOCK--The Board of Directors of the Company has
adopted a Certificate of Designations creating a series of convertible preferred
stock consisting of 1,000,000 shares, par value $.01 per share, none of which
was outstanding as of December 31, 1997 and 1996. Shares of the convertible
preferred stock may be issued from time to time in one or more series with such
designations, voting powers, if any, preferences, and relative participating,
optional or other special rights, and such qualifications, limitations and
restrictions thereof, as are determined by resolution of the Board of Directors
of the Company. However, the holders of the shares of the convertible preferred
stock will not be entitled to receive liquidation preference of such shares,
until the liquidation preference of any other series or class of the Company's
stock hereafter issued that ranks senior as to liquidation rights to the
cumulative convertible preferred stock has been paid in full.
CUMULATIVE CONVERTIBLE PREFERRED STOCK--Holders of shares of cumulative
convertible preferred stock will be entitled to receive, when and if declared by
the Board of Directors out of funds at the time legally available, cash
dividends at a maximum annual rate of $1.20 per share, payable quarterly,
commencing 90 days after the date of first issuance. Dividends are cumulative
from the date of issuance of the cumulative convertible preferred stock. During
1997 and 1996, $77,365 and $25,788 was declared and paid in cumulative preferred
stock dividends. The Company has undeclared and unpaid dividends in the amount
of $180,518 ($1.50 per share) on its cumulative preferred stock for the period
from May 1, 1995 to
F-10
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. STOCKHOLDERS' EQUITY: (CONTINUED)
December 31, 1997. The Company is not required to declare and pay such
dividends; however, until such dividends are paid current, the Company is
precluded from paying dividends to its common shareholders.
In the event of any liquidation, dissolution or wind-up of the Company,
holders of shares of cumulative convertible preferred stock are entitled to
receive the liquidation preference of $10.00 per share, plus an amount equal to
any accrued and unpaid dividends to the payment date, before any payment or
distribution is made to the holders of common stock, or any series or class of
the Company's stock hereafter issued, that will rank junior as to liquidation
rights to the cumulative convertible preferred stock.
The holders of cumulative convertible preferred stock will not have voting
rights except as required by law in connection with certain defaults and as
provided to approve certain future actions including any changes in the
provisions of the stock or the issuance of additional shares equal or senior to
the stock. Whenever dividends on the cumulative convertible preferred stock have
not been paid in an aggregate amount equal to at least six quarterly dividends,
the number of directors of the Company will be increased by two and the holders
of preferred stock will be entitled to elect these additional directors.
REDEMPTION--The cumulative convertible preferred stock is redeemable for
cash, in whole or in part, at the option of the Company, at $10.00 per share,
plus any accrued and unpaid dividends, whether or not declared.
OPTIONAL CONVERSION--At any time after the initial issuance of the
cumulative convertible preferred stock and prior to the redemption thereof, the
holders of cumulative convertible preferred stock shall have the right,
exercisable at their option, to convert any or all of such shares into common
stock at the rate of conversion described below. During 1997 no shares of
cumulative convertible preferred stock were converted to common stock under the
original conversion terms. Automatic Conversion--If, at any time after the
initial issuance thereof, the last reported sales price of the cumulative
convertible preferred stock as reported on the NASDAQ System (or the closing
sale price as reported on any national securities exchange on which the
cumulative convertible preferred stock is then listed), shall, for a period of
10 consecutive trading days, exceed $13.00, then, effective as of the closing of
business on the tenth such trading day, all shares of cumulative convertible
preferred stock then outstanding shall immediately and automatically be
converted into shares of common stock and warrants at the rate of conversion
described below.
CONVERSION RATE--The conversion rate for the cumulative convertible
preferred stock (i.e., the number of shares of common stock into which each
share of cumulative convertible preferred stock is convertible) is determined by
dividing the conversion price then in effect by $30.00. The initial conversion
price is $60.00; therefore, the cumulative convertible preferred stock is
initially convertible into common stock and Series A Warrants at the conversion
rate of one-third ( 1/3) share of common stock and one-third ( 1/3) Series A
Warrant for each share of cumulative convertible preferred stock converted.
WARRANTS--Each Series A Warrant issued in the initial public offering and in
the conversion of the cumulative convertible preferred stock entitles the holder
thereof to purchase one-sixth ( 1/6) share of common stock at a price equal to
$6.00, until five years from the effective date of the initial public offering.
The Warrants will, unless exercised or amended, expire on November 13, 1998.
Outstanding Series A Warrants may be redeemed by the Company for $1.25 each on
30 days notice. As of December 31, 1997 and 1996, there were 263,013 Series A
Warrants outstanding.
F-11
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. STOCKHOLDERS' EQUITY: (CONTINUED)
Each Series B Warrant issued in the August 1996 public securities offering
entitles the holder to purchase one-sixth ( 1/6) share of common stock for
$2.025 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 has 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 expires five (5) years from the effective date of the Company's initial
public offering. 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 are being amortized using the interest method with an unamortized
balance of $27,163 at December 31, 1997.
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. If additional funds are not
borrowed from the bank, a portion of the warrants will be returned. The Company
has recorded the warrants, which are not subject to return at their fair value
of approximately $33,000. The warrants subject to return will be recorded when
additional funds are borrowed.
On January 15, 1997, the Board of Directors authorized the Company to enter
into an agreement with Riches In Resources, Inc. 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 in common stock at the
election of the Company. The Company elected to compensate Riches In Resources,
Inc. partially in cash and partially in stock, therefore Riches In Resources,
Inc. was issued 11,667 shares of common stock during 1997. At December 31, 1997,
the Company had prepaid consultant costs of $17,701 in association with this
transaction.
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.
EMPLOYEE OPTION PLAN--1997--The plan authorizes the issuance of up to
115,892 options to purchase one (1) share of common stock. Options to purchase
100,167 shares of common stock at prices ranging from $3.78 to $11.28 are
currently outstanding of which 5,167 expire in June of 1998.
F-12
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. STOCKHOLDERS' EQUITY: (CONTINUED)
Under the plan, the Board may grant options to officers and other employees
and shall provide for an automatic receipt of options by directors who are not
full time 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.
STOCK INCENTIVE OPTION PLAN--1996--The 1996 stock incentive option plan was
approved by the Company's stockholders in June, 1996, and 58,333 shares of
common stock were initially reserved for issuance thereunder.
Currently, all options under the plan have expired or have been canceled by
the Board of Directors other than 21,667 options currently outstanding, of which
19,333 expire by June of 1998.
MANAGEMENT INCENTIVE STOCK PLAN
The Plan initially authorized the issuance of up to 40,000 units. Each unit
consists of (i) an option to purchase one (1) 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 is 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 other than 8,000 units currently
outstanding, 7,000 of which expire by June 1998.
The following table summarizes activity under the Company's stock option
plans for the years ended December 31, 1997 and 1996.
<TABLE>
<CAPTION>
EMPLOYEE
INCENTIVE MANAGEMENT STOCK INCENTIVE OPTION
STOCK OPTION PLAN INCENTIVE STOCK PLAN OPTION PLAN--1997 PLAN--1997
------------------------ ------------------------ ------------------------ -----------
1997 1996 1997 1996 1997 1996 1997
----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Shares available for grant.... -- 30,000 -- 20,000 1,333 58,533 115,892
Shares under option at end of
period...................... -- 30,000 8,000 18,667 20,333 57,000 100,167
Option price per share........ -- $ 10.074 $12.00-21.00 $12.00-21.00 $8.82-12.75 $8.82-12.75 $3.78-11.28
Shares exerciseable at end of
period...................... -- 26,000 8,000 17,000 6,778 -- 90,667
Sales exercised during the
period...................... -- -- -- -- -- -- --
Sales canceled................ 30,000 -- 10,667 17,000 36,667 --
Weighted option price......... -- $ 10.074 $ 18.12 $ 18.54 $ 10.02 $ 9.414 $ 4.20
</TABLE>
STOCK OPTION PLANS--The Company has three fixed option plans which reserve
shares of common stock for issuance to executives, key employees and directors.
The Company has adopted the disclosure-only
F-13
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. STOCKHOLDERS' EQUITY: (CONTINUED)
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
three stock option plans been determined based on fair value at the grant date
for awards in 1997 and 1996 consistent with the provisions of SFAS No. 123, the
Company's net loss applicable to common stockholders and net loss per common and
common equivalent share would have been the pro forma amounts indicated below:
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
Net loss applicable to common stockholders--as reported............................ $ (5,056,956) $ (5,128,172)
------------- -------------
------------- -------------
Net loss applicable to common stockholders--pro forma.............................. $ (5,679,620) $ (5,296,335)
------------- -------------
------------- -------------
Net loss per common share--as reported............................................. $ (3.07) $ (4.32)
------------- -------------
------------- -------------
Net loss per common share--pro forma............................................... $ (3.42) $ (4.44)
------------- -------------
------------- -------------
</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% and 6.50% in 1997 and 1996, respectively; and expected lives of five
(5) years.
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 are entitled to receive certain Incentive Payments and
Contract Settlement Payments upon the consummation of such a transaction. Their
existing employment agreements will terminate upon the consummation of a
significant corporate transaction.
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
F-14
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. STOCKHOLDERS' EQUITY: (CONTINUED)
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 tradeable and the discount was appropriate
to reflect the actual fair market value of the illiquid 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."
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES OF LENGTH OF ORIGINAL
UNDERLYING MARKET PRICE OF EXERCISE OPTION TERM
OPTIONS/SARS STOCK AT TIME OF PRICE AT TIME NEW REMAINING AT DATE
REPRICED OR REPRICING OR OF REPRICING EXERCISE OF REPRICING OR
NAME DATE AMENDED AMENDMENT OR AMENDMENT PRICE AMENDMENT (MONTHS)
- ----------------------------------- --------- ------------- ----------------- ------------- ----------- -------------------
<S> <C> <C> <C> <C> <C> <C>
David W. Berry..................... 12/3/97 20,000(1) $ 5.82 $ 9.72 $ 3.78 102
President and 12/3/97 4,000(2) $ 5.82 $ 18.60 $ 3.78 69
Chief Executive Officer
David B. Christofferson............ 12/3/97 30,000(3) $ 5.82 $ 10.08 $ 3.78 62
Executive Vice 12/3/97 4,000(2) $ 5.82 $ 18.60 $ 3.78 69
President, General 12/3/97 16,667(1) $ 5.82 $ 8.82 $ 3.78 102
Counsel and Secretary
</TABLE>
- ------------------------
(1) Consists of options to purchase shares of Common Stock pursuant to the Stock
Incentive Option Plan--1996.
(2) Consists of units, each of which included an option to purchase one (1)
share of Common Stock and a stock appreciation right ("SAR") equal to two
times the difference between the exercise price of the option and the market
value of the SAR at the date of exercise, so that one (1) unit had the value
of three (3) options, all issued pursuant to the Management Incentive Option
Plan.
(3) Consists of options to purchase 30,000 shares of Common Stock pursuant to
the Company's 1993 Incentive Stock Option Plan.
4. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA:
On September 27, 1996, the Company sold its N.E. Cedardale field located in
Major County, Oklahoma to OXY USA Inc., for consideration totaling $3,550,000
which included cash of $2,840,000 and certain exchange properties which were
concurrently sold to a third party for $710,000. The sale was effective
September 1, 1996 and the Company incurred a loss of $10,523. The properties
sold represented a substantial portion of the Company's production. In
connection with the sale, the Company recorded a loss of $212,000 resulting from
the reduction in the quantity of gas covered by a swap agreement. The Company
sold various other properties in a number of different transactions during 1997
and 1996. These sales resulted in an aggregate gain of approximately $485,813
and $272,000 for 1997 and 1996, respectively.
F-15
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. GAS SALE AGREEMENT:
Effective December 1, 1991, the Company entered into a Gas Sale Agreement to
deliver gas to an end-user over a specified period of time in the future.
The Company was committed to deliver 7,100,000 MMBTU of gas to the purchaser
over a period of seven years beginning December 1, 1991. The Company was allowed
to deliver gas to satisfy the commitment from its own reserves or from
purchasing gas on the open market. The Company delivered 44% from purchases on
the open market for the year ended December 31, 1996 as follows:
<TABLE>
<CAPTION>
FOR YEAR ENDED
DECEMBER 31,
1996 (MMBTU)
---------------
<S> <C>
Gas purchased on open market.................................................. 43,783
Gas delivered from Company reserves........................................... 55,417
------
Total deliveries.............................................................. 99,200
------
------
</TABLE>
The purchase price under the contract was fixed at $1.50 per MMBTU over the
life of the contract. The contract required the prepayment by the purchaser of
$0.75 per MMBTU for the remaining contract obligations. On January 5, 1996, the
Company entered into an agreement with the end user to terminate the Gas Sales
Agreement as of January 31, 1996. The Company paid the end user $2,181,489 which
represents a return of its $.75 advance on 2,490,103 MMBTU of gas plus a
settlement payment of $313,912.
6. LONG-TERM DEBT:
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1997 1996
------------ ------------
<S> <C> <C>
Note payable pursuant to a credit agreement with a bank of $293,888 and $493,888 ended
December 31, 1997 and 1996 respectively, interest at LIBOR rate (reserve adjusted),
plus one and seven-eighths percent (1.875%) (7.25% at December 31, 1997 and 1996),
payable in monthly installments, due in various monthly amounts through December,
1998, collateralized by producing oil and gas properties; net of discount of $18,966
and $37,931 ending December 31, 1997 and 1996 respectively.......................... $ 274,922 $ 455,956
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest
accrued at 15%...................................................................... 864,000 681,618
Note payable to bank, interest at 7.49% to 12.5%, payable in monthly installments, due
in various amounts through 2001, collateralized by other property and equipment..... 48,843 73,978
Note payable, interest at 12%, payable monthly, principal due December 31, 1997....... 100,000 100,000
------------ ------------
1,287,765 1,311,552
Less current portion.................................................................. 401,085 304,540
------------ ------------
$ 886,680 $ 1,007,012
------------ ------------
------------ ------------
</TABLE>
F-16
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. LONG-TERM DEBT: (CONTINUED)
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>
AT DECEMBER 31,
YEAR 1997
- ------------------------------------------------------------------- ---------------
<S> <C>
1998............................................................... $ 401,085
1999............................................................... 16,459
2000............................................................... 6,221
2001............................................................... --
2002............................................................... --
</TABLE>
On January 3, 1996, the Company entered into a $15,000,000 credit agreement
with a bank. The agreement provided for the immediate funding of $4,000,000
which was used to terminate the Gas Sales Agreement and repay the deferred gas
revenues incurred under the Gas Sales Agreement, payoff the note payable to a
bank due August 1, 1996, pay the bank fees related to the financing with the
remainder being used to pay current liabilities.
The remaining funds are to be available for specified future drilling and
acquisition activities of the Company subject to the approval of the bank. The
Company repaid a substantial portion of this borrowing with proceeds from the
sale of its N.E. Cedardale properties in September of 1996. Due to this early
repayment of borrowings, the Company reduced debt issuance costs by $293,000 and
discount on notes payable by $207,000 and recorded these amounts as interest
expense. The loan is secured by a mortgage on all of the Company's significant
producing properties. 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. As additional consideration for the loan, the Company assigned the bank
an overriding royalty interest in the mortgaged properties. The required
covenants during 1997 are as follows:
<TABLE>
<CAPTION>
COVENANT, AS DEFINED
- --------------------------------------------------------------------------------
<S> <C>
Tangible Net Worth.............................................................. $ 5,000,000
Current Ratio................................................................... 1.1 : 1.0
Debt to Capitalization.......................................................... 0.6 : 1.0
Cash Flow Ratio................................................................. 3.0 : 1.0
Cash on Hand.................................................................... $ 200,000
Working Capital................................................................. $ 400,000
</TABLE>
The Company does not believe it will be able to comply with certain of the
covenants. The Company has obtained a waiver of the covenant through June 30,
1998. Management believes that the Company will require an additional waiver or
waivers during 1998.
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 $28,000 at December 31,
1996. At December 31, 1997 the unrealized loss was $21,910.
F-17
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. LONG-TERM DEBT: (CONTINUED)
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 provide 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, 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.
7. INCOME TAXES:
Deferred tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Net operating tax loss carryforward............................. $ 4,332,710 $ 3,494,442
Property and equipment.......................................... (2,936,284) (1,942,813)
Employee benefits............................................... -- 76,032
Valuation allowance............................................. (3,254,886) (1,627,661)
------------- -------------
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 estimated net operating loss carryforwards
("NOLs") at December 31, 1997, of approximately $12,743,267, which may be used
to offset future taxable income. The operating loss carryforwards expire in the
tax years 2006 through 2012.
The ability of the Company to utilize NOLs and tax credit carryforwards to
reduce future federal income taxes of the Company may be subject to various
limitations under the Internal Revenue Code of 1986, as amended (the "Code").
One such limitation is contained in Section 382 of the Code which imposes an
annual limitation on the amount of a corporation's taxable income that can be
offset by those carryforwards in the event of a substantial change in ownership
as defined in Section 382 ("Ownership Change"). In general, Ownership Change
occurs if during a specified three-year period there are capital stock
transactions, which result in an aggregate change of more than 50% in the
beneficial ownership of the stock of the Company. The Company may have incurred
such an Ownership Change.
8. RELATED PARTY TRANSACTIONS:
The Company made advances to officers and affiliates of the Company during
1997 and 1996 of $48,380 and $51,143, respectively, and received repayments of
$99,216 and $18,741, respectively. The December 31, 1997 and 1996 receivables
include approximately $47,787, from an affiliated partnership for which the
Company serves as the managing general partner. During 1996, as a result of the
Company's relocation, the Company purchased the homes of two officers for a
total aggregate cost of approximately $369,000. The houses were sold for a total
aggregate sales price of approximately $354,000 and the net amount realized by
the Company was approximately $324,000.
F-18
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. COMMITMENTS AND CONTINGENCIES:
The Company leases office space under lease agreements, which are classified
as operating leases. Lease expense under these agreements was $112,432 in 1997
and $106,440 in 1996. A summary of future minimum rentals on these
non-cancelable operating leases is as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
YEAR 1997
- ------------------------------------------------------------------- ---------------
<S> <C>
1998............................................................... $ 117,068
1999............................................................... $ 117,068
2000............................................................... $ 117,068
2001............................................................... $ 78,045
</TABLE>
The Company has entered into employment agreements with two officers. Two of
these agreements expire December 31, 1999 (and automatically renew for
additional one-year terms each December 31 unless specifically terminated by
either the Company or individual). The Company has entered into an incentive
agreement and a contract settlement agreement with two officers. Their
employment agreements with the Company will be terminated upon the closing of
the Acquisitions.
Pursuant to the incentive agreements and contract settlement agreements, in
the event the Acquisitions are closed, or in the event there is another
transaction which results in a change of control of the Company, it will pay
incentive payments totaling $246,000, as well as contract settlement payments
totaling $246,000. Each of the incentive payments and the contract settlement
payments may be paid in the form of promissory notes due not later than
September 30, 1998.
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 operations, and net cash flows.
Pursuant to the credit agreement with the bank, the Company entered into a
natural gas swap agreement on 62,500 MMBTU of natural gas per month at $1.566
per MMBTU for Mid-Continent gas for the period from April 1, 1996 through
January 31, 1999. The swap was amended to 31,250 MMBTU on September 25, 1996,
due to the sale of the N.E. Cedardale field. The Company recorded a loss of
$212,000 in connection with this reduction in quantities covered by the swap
agreement. Currently the Company's monthly natural gas production is
substantially less than the natural gas swap that is in place. The total
unrealized loss on the amended swap agreement was $128,936 at December 31, 1997.
The Company has a hedge in place, which limits the potential cost per MMBTU it
may have to settle at a price of $3.13 per MMBTU, for 31,250 MMBTU per month in
January and February 1998.
10. SUBSEQUENT EVENT
On January 19, 1998, the Company entered into the Acquisition Agreement with
EPC and Aspect. Pursuant to the terms and conditions of the Acquisition
Agreement and subject to approval by the Company's shareholders the Company will
purchase from EPC (the "EPC Assets") and Aspect (the "Aspect Assets") certain
undeveloped oil and gas exploration projects in the onshore Gulf Coast area (the
"Acquisitions"). The Company will issue up to 5,165,985 shares of Common Stock
to EPC in exchange for the EPC Assets, and will issue up to 4,941,440 shares of
Common Stock to Aspect or its assigns in exchange for the Aspect Assets. As part
of the Acquisition, the Company intends to redeem its Cumulative Committee
Preferred Stock at its redemption price of $10.00 per share plus all accrued and
unpaid dividends.
F-19
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUBSEQUENT EVENT (CONTINUED)
In conjunction with the Acquisition Agreement, Aspect committed to lend the
Company up to $1,800,000, and in January and February advanced $500,000 on said
credit facility. The facility was repaid by the Company on February 23, 1998,
when the Company entered into a $7,800,000 credit agreement with Duke Energy
Financial Services, Inc. Said new credit facility provides for up to $4,800,000
prior to closing of the Acquisitions, $1,800,000 of which can be used directly
by the Company and $3,000,000 to be utilized solely to loan to EPC to pay
exploratory costs incurred on the EPC Assets after the effective date of the
Acquisitions and prior to closing thereof. An additional $3,000,000 will be
available to the Company after closing of the Acquisitions to pay additional
exploratory costs. The credit facility bears interest at a national prime rate
plus 4%. In addition, the lender will be paid cash payments equal to an
overriding royalty of 0.6% of production attributable to the Company's interest
in wells drilled by the Company while the credit facility is outstanding. The
lender also has a right to gather, process, transport and market, at competitive
market rates, natural gas produced from a majority of the projects the Company
intends to acquire pursuant to the Acquisitions. The facility is secured by
mortgages on most of the Company's undeveloped exploration projects. The assets
to be acquired in the acquisition will be subject to such mortgages. The
facility is repayable in eleven monthly payments equal to 1/30 of the principal
plus interest, plus a final monthly payment of all remaining principal plus
interest commencing August 31, 1998, or sooner in the event the Company sells
interests in the collateral or closes any underwritten public offering of
securities.
On May 14, 1998 a Special Meeting of Stockholders of the Company was held
pursuant to a solicitation of proxy mailed on or about April 24, 1998 to all the
stockholders of record as of the close of business on April 1, 1998. The
stockholders approved and ratified the following:
<TABLE>
<S> <C>
(i) the approval of the Acquisitions;
(ii) the approval of a 1:6 reverse split of the presently outstanding Common Stock;
(iii) the approval of the reincorporation of the Company in the state of Delaware and a
change in the Company's name to Esenjay Exploration, Inc.; and
(iv) the election of seven directors.
</TABLE>
As a result of the above stockholder actions, the Acquisitions were closed,
the Company's preferred stock was called for redemption and the reverse split,
reincorporation and name change were effected. Accordingly, all numbers of
common shares and per share calculations have been restated to reflect the 1:6
reverse stock split.
The Acquisition Agreement calls 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 and
its assigns for the Aspect assets. The combined assets of Aspect and EPC have a
historical full cost basis of $19.9 million and a fair market value of
$54,200,000. In addition, after the effective date and prior to the date of
closing, EPC incurred approximately $3,800,000 in exploration and development
costs associated with the prospects and Aspect incurred approximated $3,955,000
in such costs, all of which incurred costs are for the account of the Company.
F-20
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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,
--------------------------
1997 1996
------------ ------------
<S> <C> <C>
Acquisition of properties
Proved.................................................................... $ 765,678 $ 1,305,219
Unproved.................................................................. 242,205 644,323
Exploration costs........................................................... 1,861,432 182,147
Development costs........................................................... 153,938 313,152
------------ ------------
Total costs incurred.................................................... $ 3,023,253 $ 2,444,841
------------ ------------
------------ ------------
</TABLE>
CAPITALIZED COSTS:
<TABLE>
<CAPTION>
AT DECEMBER 31,
---------------------------
1997 1996
------------ -------------
<S> <C> <C>
Proved and unproved properties being amortized............................. $ 1,181,811 $ 4,681,518
Unproved properties not being amortized.................................... 2,054,037 598,596
Less accumulated amortization.............................................. (438,044) (2,277,984)
------------ -------------
Net capitalized costs.................................................. $ 2,797,804 $ 3,002,130
------------ -------------
------------ -------------
</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.
F-21
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED): (CONTINUED)
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 (BARRELS)
NATURAL GAS (MCF) ---------------------
--------------------------
YEARS ENDED DECEMBER
YEARS ENDED DECEMBER 31, 31,
-------------------------- ---------------------
1997 1996 1997 1996
----------- ------------- --------- ----------
<S> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of period......................................... 8,901,555 18,564,141 183,735 279,501
Purchases of minerals-in-place.............................. -- 2,615,187 -- 84,096
Sales of minerals-in-place.................................. (159,528) (10,092,754) (3,857) (187,006)
Revisions of previous estimates............................. (3,129,076) (791,059) (59,121) 8,534
Extensions, discoveries and other additions................. 8,715 12,056 928 7,886
Production.................................................. (121,304) (1,406,016) (7,286) (9,276)
----------- ------------- --------- ----------
End of period............................................... 5,500,363 8,901,555 114,399 183,735
----------- ------------- --------- ----------
----------- ------------- --------- ----------
Proved developed reserves:
Beginning of period......................................... 985,524 7,307,717 46,420 72,515
----------- ------------- --------- ----------
----------- ------------- --------- ----------
End of period............................................... 521,345 985,524 24,358 46,420
----------- ------------- --------- ----------
----------- ------------- --------- ----------
</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, 1997 and 1996 were as follows: 1997--$2.46 per
MCF--Gas, $15.70 per barrel--Oil; 1996--$4.13 per MCF--Gas, $24.42 per
barrel--Oil, respectively. Future net cash flows are then calculated by reducing
such estimated cash inflows by the estimated future expenditures (based on
current costs) to be incurred in developing and producing the proved reserves
and by the estimated future income taxes. Estimated future income taxes are
computed by applying the appropriate year-end tax rate to the future pretax net
cash flows relating to the Company's estimated proved oil and gas reserves. The
estimated future income taxes give effect to permanent differences and tax
credits and allowances.
F-22
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED): (CONTINUED)
The following table sets forth the Company's estimated standardized measure
of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Future cash inflows................................................................ $ 15,752,040 $ 41,251,837
Future development and production costs............................................ (7,468,887) (8,288,416)
Future income tax expenses......................................................... (365,224) (6,628,489)
------------- -------------
Future net cash flows.............................................................. 7,917,929 26,334,932
Discount........................................................................... (4,019,429) (9,576,388)
------------- -------------
Standardized measure of discounted future net cash flows........................... $ 3,898,500 $ 16,758,544
------------- -------------
------------- -------------
</TABLE>
The following table sets forth changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1996
-------------- --------------
<S> <C> <C>
Standardized measure of discounted future cash flows--beginning of period......... $ 16,758,544 $ 16,404,620
Sales of oil and gas produced, net of operating expenses.......................... (312,198) (1,977,577)
Net changes in sales prices and production costs.................................. (10,601,580) 7,177,867
Extensions, discoveries and improved recovery, less related costs................. 30,952 187,877
Change in future development costs................................................ (433,134) (17,400)
Previously estimated development costs incurred during the year................... 162,610 115,440
Revisions of previous quantity estimates.......................................... (4,973,603) (1,940,104)
Accretion of discount............................................................. 2,169,632 2,004,973
Net change of income taxes........................................................ 4,810,619 (1,292,670)
Purchases of minerals-in-place.................................................... -- 7,787,886
Sales of minerals-in-place........................................................ (371,728) (11,270,558)
Changes in production rates (timing) and other.................................... (3,341,614) (421,810)
-------------- --------------
Standardized measure of discounted future cash flows--end of period............... $ 3,898,500 $ 16,758,544
-------------- --------------
-------------- --------------
</TABLE>
F-23
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
<TABLE>
<CAPTION>
MARCH 31,
1998
-------------
<S> <C>
Current assets:
Cash and cash equivalents........................................................................ $ 188,495
Accounts receivable, net of allowance for doubtful accounts of $7,915 at March 31, 1998.......... 176,507
Prepaid expenses and other....................................................................... 141,074
Current portion notes receivable from EPC........................................................ 466,664
Receivables from affiliates...................................................................... 97,765
-------------
Total current assets........................................................................... 1,070,505
Property and equipment:
Gas and oil properties, at cost-successful efforts method of accounting.......................... 3,635,538
Other property and equipment..................................................................... 1,151,592
-------------
4,787,130
Less accumulated depletion, depreciation and amortization........................................ (1,295,435)
-------------
3,491,695
Other assets....................................................................................... 513,856
Notes receivable from EPC.......................................................................... 1,283,336
-------------
Total assets................................................................................... $ 6,359,392
-------------
-------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................................. $ 824,440
Revenue distribution payable..................................................................... 74,325
Current portion of long-term debt................................................................ 988,360
Accrued and other liabilities.................................................................... 331,964
-------------
Total current liabilities...................................................................... 2,219,089
Long-term debt..................................................................................... 1,846,165
Non-recourse debt.................................................................................. 864,000
Accrued interest on non-recourse debt.............................................................. 227,114
Other long-term liabilities........................................................................ --
-------------
Total liabilities.............................................................................. 5,156,368
Commitments and contingencies
Stockholders' equity:
Cumulative convertible preferred stock $.01 par value, 5,000,000 shares authorized; 85,961 shares
issued and outstanding at March 31, 1998 ($859,610 aggregate liquidation preference at March
31, 1998....................................................................................... 860
Common Stock:
Class A common stock, $.01 par value, 40,000,000 shares authorized; 1,655,984 outstanding at
March 31, 1998(1)............................................................................. 16,560
Unamortized value of warrants issued............................................................. (20,371)
Additional paid-in capital (1)................................................................... 14,751,425
Accumulated Deficit.............................................................................. (13,545,450)
-------------
Total stockholders' equity..................................................................... 1,203,024
-------------
Total liabilities and stockholders' equity..................................................... $ 6,359,392
-------------
-------------
</TABLE>
- ------------------------
(1) After giving effect to the 1:6 reverse stock split effected on May 14, 1998.
See Note 6.
The accompanying notes are an integral part of these financial statements
F-24
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
--------------------------
1998 1997
----------- -------------
<S> <C> <C>
Revenues:
Gas and oil revenues................................................................ $ 48,503 $ 327,435
Realized gain (loss) on commodity transactions...................................... (47,875) (121,937)
Unrealized loss on commodity transactions........................................... (51,011) --
Gain on sale of assets.............................................................. 2,875 132,035
Operating fees...................................................................... 6,992 14,234
Other revenues...................................................................... 23,930 53,880
----------- -------------
Total revenues.................................................................... (16,586) 405,647
----------- -------------
Costs and expenses:
Lease operating expense............................................................. 69,773 96,698
Production taxes.................................................................... (1,090) 8,784
Transportation and gathering costs.................................................. 639 90,394
Depletion, depreciation and amortization............................................ 53,568 132,774
Exploration costs................................................................... 3,560 852,626
Interest expense.................................................................... 19,223 4,133
General and administrative expense.................................................. 459,014 572,260
Delay rentals....................................................................... (12,685) --
----------- -------------
Total costs and expenses.......................................................... 592,002 1,757,669
----------- -------------
Loss before provision for income taxes................................................ (608,588) (1,352,022)
Benefit (provision) for income taxes.................................................. -- --
----------- -------------
Net loss.............................................................................. (608,588) (1,352,022)
Cumulative preferred stock dividend................................................... 25,788 25,788
----------- -------------
Net loss applicable to common stockholders............................................ $ (634,376) $ (1,377,810)
----------- -------------
----------- -------------
Net loss per share(1)................................................................. $ (0.38) $ (1.16)
----------- -------------
----------- -------------
Weighted average number of common shares outstanding(1)............................... 1,655,984 1,644,317
</TABLE>
- ------------------------
(1) After giving effect to the 1:6 reverse stock split effected May 14, 1998.
See Note 6.
The accompanying notes are an integral part of these financial statements.
F-25
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-----------------------
1998 1997
---------- -----------
<S> <C> <C>
Cash flows from operating activities:
Net loss.............................................................................. $ (608,588) $(1,352,022)
Adjustments to reconcile net loss to net cash (used) in operating activities:
Depletion, depreciation and amortization............................................ 53,568 132,774
Impairment of oil and gas properties................................................ -- --
Gain on sale of assets.............................................................. (2,875) (132,035)
Amortization of financing costs and warrants........................................ 21,564 30,343
Unrealized loss on commodity transactions........................................... 51,011 --
Exploration costs................................................................... 3,560 852,626
Changes in operating assets and liabilities
Trade and affiliate receivables................................................... 52,763 (23,282)
Prepaid expenses and other........................................................ 108,254 170,295
Other assets...................................................................... (359,188) (1,028)
Accounts payable.................................................................. (86,956) (11,760)
Revenue distribution payable...................................................... 6,194 (173,684)
Accrued and other................................................................. 4,171 (158,993)
---------- -----------
Net cash (used) in operating activities........................................... (756,522) (348,280)
---------- -----------
Cash flows used in investing activities:
Capital expenditures--gas and oil properties.......................................... (403,250) (1,330,312)
Capital expenditures--other property and equipment.................................... (13,328) (73,646)
Notes receivable from EPC............................................................. (1,750,000) --
Proceeds from sale of assets.......................................................... 15,000 540,568
---------- -----------
Net cash provided by (used) in investing activities................................. (2,151,578) (863,390)
---------- -----------
Cash flows from financing activities:
Proceeds from issuance of debt........................................................ 3,000,000 225,534
Repayments of long-term debt.......................................................... (593,981) (74,443)
Debt issuance costs................................................................... -- --
Preferred stock dividends paid........................................................ -- (25,788)
---------- -----------
Net cash provided by (used) in financing activities................................. 2,406,019 125,303
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Net increase (decrease) in cash and cash equivalents.................................. (502,081) (1,086,867)
Cash and cash equivalents at beginning of period........................................ 690,576 4,956,686
---------- -----------
Cash and cash equivalents at end of period.............................................. $ 188,495 $ 3,869,789
---------- -----------
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Supplemental disclosure of cash flow information:
Cash paid for interest................................................................ $ 98,325 $ 34,157
---------- -----------
---------- -----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-26
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The accompanying unaudited condensed consolidated financial statements of
Esenjay Exploration, Inc. and its subsidiaries (the "Company") have been
prepared in accordance with generally accepted accounting principles for interim
financial information. Accordingly they do not include all of the information
and footnotes required by generally accepted accounting principles for complete
financial statements. Interim results are not necessarily indicative of results
for a full year.
A summary of the Company's significant accounting policies is presented on
pages 30 and 31 of its 1997 Form 10KSB/A filed with the SEC. Users of financial
information are encouraged to refer to the footnotes contained therein when
reviewing interim financial results. There have been no material changes in the
accounting policies followed by the Company during 1998.
The accompanying interim financial statements contain all the material
adjustments, which are in the opinion of management, consistent with the
adjustments necessary to present the fairly stated consolidated financial
position, results of operations, cash flows and stockholder's equity of the
Company for the interim period. Certain prior period amounts have been
reclassified to conform with the current period presentation.
2. LONG-TERM DEBT:
Long-term debt consists of the following:
<TABLE>
<CAPTION>
MARCH 31,
1998
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<S> <C>
Note payable pursuant to a credit agreement with a bank of $218,888 at March 31, 1998 interest at
LIBOR rate (reserve adjusted), plus one and seven-eights percent (1.875%)(7.25% at March 31,
1998), payable in monthly installments, due in various monthly amounts through December 1998,
collateralized by producing oil and gas properties, net of discount of $14,224 at March 31,
1998.............................................................................................. $ 204,664
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest accrued at 15%..... 864,000
Notes payable to bank, interest at 7.49% to 12.5%, payable in monthly installments, due in various
amounts through 2001, collateralized by other property and equipment.............................. 29,861
Note payable, interest at 12%, payable monthly, principal due December 31, 1997..................... 100,000
Note payable pursuant to a credit agreement with an energy lending institution, $2,500,000 at March
31, 1998, interest at prime rate plus 4% payable monthly, principal due in eleven monthly
installments commencing August 31, 1998........................................................... 2,500,000
------------
3,698,525
Less current portion................................................................................ 988,360
------------
$ 2,710,165
------------
------------
</TABLE>
On January 3, 1996, the Company entered into a $15,000,000 credit agreement
with a bank. The agreement provided for the immediate funding of $4,000,000
which was used to terminate the Gas Sales Agreement and repay the deferred gas
revenues incurred under the Gas Sales Agreement, payoff the note payable to a
bank due August 1, 1996, pay the bank fees related to the financing with the
remainder being used to pay current liabilities. The remaining funds will be
available for specified future drilling and
F-27
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
2. LONG-TERM DEBT: (CONTINUED)
acquisition activities of the Company subject to the approval of the bank. The
Company repaid a substantial portion of this borrowing with proceeds from the
sale of its N.E. Cederdale properties in September of 1996. Due to this early
repayment of borrowings, the Company reduced debt issuance costs by $293,000 and
discount on notes payable by $207,000 and recorded these amounts as interest
expense. The loan is secured by a mortgage on all of the Company's significant
producing properties. As part of the credit agreement, the Company is subject to
certain covenants and restriction, among which are the limitations on additional
borrowing, and sales of significant properties, working capital, cash, and net
worth maintenance requirements and minimum debt to net worth ratio. As
additional consideration for the loan, the Company assigned the bank an
overriding royalty interest in the mortgaged properties. The required covenants
during 1998 are as follows:
<TABLE>
<CAPTION>
COVENANT AS DEFINED
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<S> <C>
Tangible Net Worth.............................................................. $ 5,000,000
Current Ratio................................................................... 1,1:1,0
Debt to Capitalization.......................................................... 0.6:1.0
Cash Flow Ratio................................................................. 3.0:1.0
Cash on Hand.................................................................... $ 200,000
Working Capital................................................................. $ 400,000
</TABLE>
The Company has not been able and, does not believe it will be able, to
comply with certain of the covenants. The Company has obtained a waiver of the
covenants through June 30, 1998. Management believes that the Company will
require an additional waiver or waivers during 1998.
In addition, the Company entered into an interest rate swap guaranteeing a
fixed interest rate of 8.28% on the loan, and the Company will have paid fees of
one-eighth of 1% (.0125%) on the unused portion of the commitment amount. On
April 24, 1998, the Company settled this swap agreement resulting in a realized
loss of $28,500.
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 provide a non-recourse loan to fund 48%
of the Company's 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 March 31, 1998, 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. The
loan is now fully funded.
In conjunction with the Acquisition Agreement, Aspect committed to lend the
Company up to $1,800,000, and in January and February advanced $500,000 on said
credit facilty. The facility was repaid by the Company on February 23, 1998,
when the Company entered into a $7,800,000 credit agreement with Duke Energy
Financial Services, Inc (the "Duke Credit Facililty"). The Duke Credit Facility
provides for borrowings of up to $4,800,000 prior to closing of the
Acquisitions, $1,800,000 of which was used directly by the Company and
$3,000,000 of which was loaned to EPC to pay exploratory costs incurred on the
assets acquired from EPC in the Acquisitions after the effective date of the
Acquisitions and prior to closing thereof. An additional $3,000,000 became
available to the Company after closing of the Acquisitions to pay additional
exploratory costs and to fund the costs of redemption of the Company's
convertible preferred
F-28
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
2. LONG-TERM DEBT: (CONTINUED)
stock. The Duke Credit Facility bears interest at a national prime rate plus
4.0%. In addition, the lender will be paid cash payments equal to an overriding
royalty of 0.6% of the Company's interest in wells drilled by the Company while
the credit facility is outstanding. The lender also has a right to gather,
process, transport and market, at competitive market rates, natural gas produced
from a majority of the projects the Company acquired pursuant to the
Acquisitions. The facility is secured by mortgages on most of the Company's
undeveloped exploration projects. The assets acquired in the Acquisitions are
subject to such mortgages. The facility is repayable in eleven monthly payments
equal to 1/30 of the principal plus interest, plus a final monthly payment of
all remaining principal plus interest commencing August 31, 1998, or sooner in
the event the Company sells interests in the collateral or closes any
underwritten public offering of securities.
3. DISPOSITION OF OIL AND GAS PROPERTIES
In the first quarter of 1997 the Company divested its interest in a well
located in Oklahoma and promoted its interest in a prospect located in South
Louisiana for a total of $381,321 and realized a gain of $166,143. This gain was
partially offset by a realized loss of $34,108 which was associated with the
relocation of the Company headquarters to Houston, Texas. There was no such
activity in the first quarter of 1998.
4. NOTES RECEIVABLE FROM EPC
The Duke Credit Facility provides for borrowings of up to $4,800,000 prior
to the closing of the Acquisitions, of which $3,000,000 was used to make loans
to EPC to pay exploratory costs incurred on the assets acquired by the Company
in the Acquisitions, which costs were incurred after the effective date of the
Acquisition Agreement and prior to closing. The Duke Credit Facility bears an
interest rate at a national prime rate plus 4.0%. The Duke Credit Facility is
repayable in eleven monthly payments equal to 1/30 of the principal, plus
interest, and a final monthly payment of the remaining principal and interest,
commencing on August 31, 1998. As of March 31, 1998, the funds expended in
connection with these exploratory costs were $1,750,000, of which $466,664
represented the current portion and $1,283,336 represented the long-term
portion.
5. COMMITMENTS AND CONTINGENCIES
The Company previously entered into employment agreements with two officers
that covered periods through December 31, 1999. In 1997 the Company entered into
incentive agreements and contract settlement agreements with the two officers.
Pursuant to the incentive agreements and contact settlement agreements, upon the
closing of the Acquisitions, the Company became obligated to pay incentive
payments totaling $246,000, as well as contract settlement payments totaling
$246,000 to said officers. Each of the incentive payments and the contract
payments may be paid in the form of promissory notes due not later than
September 30, 1998. Upon closing of the Acquisitions the employment agreements
were settled by execution of such promissory notes.
The Company is a 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 operations and net cash flows.
F-29
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
5. COMMITMENTS AND CONTINGENCIES (CONTINUED)
Pursuant to the credit agreement with the bank, the Company entered into a
natural gas swap agreement on 62,500 MMBTU of natural gas per month at $1.566
per MMBTU for Mid-Continent gas for the period from April 1, 1996 through
January 31, 1999. The swap was amended to 31,250 MMBTU on September 25, 1996,
due to the sale of the N.E. Cedardale field. The Company recorded a loss of
$212,000 in connection with this reduction in quantities covered by the swap
agreement. Currently the Company's monthly natural gas production is
substantially less than the natural gas swap that is in place. The total
unrealized loss on the amended swap agreement was $179,947 at March 31, 1998.
6. SUBSEQUENT EVENT
On May 14, 1998 a Special Meeting of Stockholders of the Company was held
pursuant to a solicitation of proxy mailed on or about April 24, 1998 to all the
stockholders of record as of the close of business on April 1, 1998. The
stockholders approved and ratified the following:
<TABLE>
<S> <C>
(i) the approval of the Acquisition Agreement;
(ii) the approval of a 1:6 reverse split of the presently outstanding Common Stock;
(iii) the approval of the reincorporation of the Company in the state of Delaware and a
change of the Company's name to Esenjay Exploration, Inc.; and
(iv) the election of seven directors.
</TABLE>
As a result of the above stockholder actions, the Acquisitions were closed,
the Company's preferred stock was called for redemption and the reverse split,
reincorporation and name change were effected. Accordingly, all numbers of
common shares and per share calculations have been restated to reflect the 1:6
reverse stock split.
The Acquisition Agreement calls 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 and
its assigns for the Aspect assets. The combined assets of Aspect and EPC have a
historical full cost basis of $19.9 million and a fair market value of
$54,200,000. In addition, after the effective date and prior to the date of
closing, EPC incurred approximately $3,800,000 in exploration and development
costs associated with the prospects and Aspect incurred approximated $3,955,000
in such costs, all of which incurred costs were for the account of the Company.
F-30
<PAGE>
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NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THIS OFFERING OTHER
THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY OR BY ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN
OFFER TO SELL OR SOLICITATION OF AN OFFER TO BUY BY ANYONE IN ANY JURISDICTION
IN WHICH SUCH OFFER TO SELL OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE
PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO, OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY
CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT AS
OF ANY TIME SUBSEQUENT TO THE DATE HEREOF.
------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary........................................................ 3
Cautionary Statement Regarding Forward-Looking Statements................. 10
Risk Factors.............................................................. 10
Use of Proceeds........................................................... 21
Dividend Policy........................................................... 22
Price Range of Common Stock............................................... 22
Capitalization............................................................ 23
Pro Forma Financial Statements............................................ 24
Selected Financial Data................................................... 28
Management's Discussion and Analysis of Financial Condition and Results of
Operations.............................................................. 30
Business and Properties................................................... 37
Management................................................................ 57
Principal Stockholders.................................................... 64
Certain Transactions...................................................... 65
Description of Securities................................................. 67
Underwriting.............................................................. 70
Legal Matters............................................................. 72
Experts................................................................... 72
Available Information..................................................... 72
Glossary of Certain Industry Terms........................................ 73
Index to Financial Statements............................................. F-1
</TABLE>
4,000,000 SHARES
[LOGO]
COMMON STOCK
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P R O S P E C T U S
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GAINES, BERLAND INC.
JULY 16, 1998
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