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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB/A
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission file number: 0-22782
ESENJAY EXPLORATION, INC.
(Exact name of small business issuer in its charter)
DELAWARE 73-1421000
(State of incorporation) (I.R.S. Employer Identification Number)
500 N. WATER STREET, SUITE 1100
CORPUS CHRISTI, TEXAS 78471
(Address of registrant's principal executive offices, including zip code)
Registrant's telephone number, including area code: (512) 883-7464
Securities registered under Section 12(b) of the Exchange Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
None None
Securities registered under Section 12(g) of the Exchange Act:
COMMON STOCK
SERIES B COMMON STOCK PURCHASE WARRANTS
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-B is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this
Form 10-KSB or any amendment to this Form 10-KSB. [X]
State issuer's revenues for its most recent fiscal year: $1,716,473
The aggregate market value of the voting stock held by non-affiliates
of the registrant (treating all executive officers and directors of the
registrant, for this purpose, as if they may be affiliates of the registrant)
was approximately $19,731,042 on March 26, 1999 (based on the last sales
price of $1.25 per share as reported on the NASDAQ Stock Market).
15,784,834 shares as the registrant's common stock were outstanding
as of March 26, 1999.
DOCUMENTS INCORPORATED BY REFERENCE
Registrant's Proxy Statement for its 1998 Annual Meeting of Stockholders
is incorporated by reference into Part III.
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ESENJAY EXPLORATION, INC.
FOR YEAR ENDED DECEMBER 31, 1998
TABLE OF CONTENTS
FORM 10-KSB/A
PART I
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ITEM PAGE
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1. Description of Business............................................... 3
2. Description of Property............................................... 20
3. Legal Proceedings..................................................... 22
4. Submission of Matters to a Vote of Security Holders................... 22
PART II
5. Market for Common Equity and Related Stockholder Matters.............. 23
6. Management's Discussion and Analysis or Plan of Operation............. 23
6A. Quantitative and Qualitative Disclosures about Market Risks........... 31
7. Financial Statements.................................................. 32
8. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................. 52
PART III
9. Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act................... 53
10. Executive Compensation................................................ 55
11. Security Ownership of Certain Beneficial Owners
and Management...................................................... 56
12. Certain Relationships and Related Transactions........................ 58
PART IV
13. Exhibits and Reports on Form 8-K...................................... 60
Signatures............................................................ 62
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PART I
This Form 10-KSB/A contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. The Company's actual results could differ
materially from those set forth in the forward-looking statements. Certain
factors that might cause such a difference are discussed in the introductory
paragraph to Management's Discussion and Analysis beginning on page 23 of
this Form 10-KSB.
ITEM 1. DESCRIPTION OF BUSINESS
GENERAL
THE COMPANY
Esenjay Exploration, Inc. (the "Company") is an independent energy
company engaged in the exploration for and development of natural gas and
oil. The Company has assembled an inventory of 39 technology enhanced natural
gas and oil exploration projects along the Texas and Louisiana Gulf Coast
(the "Exploration Projects"). These Exploration Projects include substantial
interests in 28 projects the Company acquired on May 14, 1998 (the
"Acquisitions") from Esenjay Petroleum Corporation ("EPC") and Aspect
Resources LLC ("Aspect") pursuant to an Acquisition Agreement and Plan of
Exchange (as amended, the "Acquisition Agreement"). The Exploration Projects
also include the Company's interests in projects acquired both before and
after consummation of the Acquisitions. The Company, EPC and Aspect have
spent several years identifying and evaluating many of the Exploration
Projects. Each of the Exploration Projects differs in scope and character and
consists of one or more types of assets, such as 3-D seismic data, leasehold
positions, lease options, working interests in leases, royalty interests or
other mineral rights.
In connection with the Acquisitions, an affiliate of Enron Corp.
exercised an option to exchange $3.8 million of debt Aspect owed to such
Enron affiliate for 675,000 shares of the Company's Common Stock that would
otherwise have been issued to Aspect in the Acquisitions, at an effective
conversion rate of $5.63 per share. As a result of the Acquisitions and this
exchange and the underwritten offering described below, EPC, Aspect and the
Enron affiliate own approximately 32.8%, 27.7% and 4.3%, respectively, of the
Company's outstanding Common Stock.
On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering
the Company had 15,762,723 shares outstanding.
OVERVIEW OF CURRENT ACTIVITIES AND RECENT EVENTS. The Exploration
Projects encompass a relatively large number of properties which the Company
intends to drill and/or otherwise exploit on a property by property basis
over a period of time based upon various factors including terms and
locations of leases, updated current drilling results, and the overall
Company exploration strategy.
The Company utilizes the successful efforts method of accounting.
Under this method it expenses its dry hole costs and the field acquisition
costs of 3-D seismic data as incurred. The undeveloped properties which were
acquired pursuant to the Acquisitions, and which were comprised primarily of
interests in unproven 3-D seismic based projects, recorded in May of 1998 at
an independently estimated fair market value of $54.2 million as determined
by Cornerstone Ventures, L.P., a Houston, Texas based investment banking
firm. Pursuant to the successful efforts method of accounting, the Company is
amortizing such initial costs as periodic impairments of unproved properties
on a straight-line basis over a period not to exceed forty-eight months, as
well as recognizing property specific impairments. These non-cash charges
effect all such costs which are not, in the accounting period they are to be
impaired, supported by proven oil and gas reserves. Hence significant
non-cash charges will likely depress reported earnings of the Company over
the next several years, but will not effect cash flows provided by operating
activities nor the ultimate realizable value of the Company's natural gas and
oil properties.
Most of the Exploration Projects have been enhanced with 3-D seismic
data in conjunction with computer aided exploration ("CAEX") technologies.
The 3-D seismic data acquired to date covers approximately 1,700 square
miles. A significant number of the Exploration Projects have reached the
drilling stage, and the Company has budgeted approximately $16.5 million, in
addition to funds already spent, to fund its drilling budget in 1999. It has
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also budgeted approximately $7.5 million for additional land and geophysical
costs for a total 1999 capital expenditure budget of approximately
$24.0 million. The budget is projected to fund the Company's net cost in over
40 wells. The Company does not currently have capital resources to fund the
complete 1999 budget but believes such resources or other optional means of
exploration funding will be available. (See Management's Discussion and
Analysis - Liquidity and Capital Resources). The Company believes that the
Exploration Projects represent a diverse array of technology enhanced, 3-D
seismic evaluated, ready to drill natural gas exploration projects.
The Company entered 1999 having gone from nominal second quarter
1998 gas and oil revenues of approximately $35,000 per month and large
operating cash flow deficits to a company with over $360,000 per month in oil
and gas revenues in the fourth quarter of 1998. This number is expected to
exceed $700,000 per month as first quarter 1999 exploration discoveries come
on line and continue to increase as additional wells are drilled. This should
allow it to achieve positive operating cash flow in 1999 and beyond. In
addition, since December 31, 1998, the Company has closed a long term
financing commitment for $9,000,000 with Duke Energy Field Services, Inc., it
has closed a sale of project interests to industry partners for a total of
$3,768,500, and has entered into two preliminary agreements to sell
additional project interests, which it expects to close in April 1999, for a
total of approximately $3,900,000. The closed financing, combined with the
closed project sales, as well as those expected to close, will result in an
aggregate availability of over $16,600,000 in available cash resources, which
is expected to enhance working capital and contribute to the Company's early
1999 capital expenditure plan. (See "See Management's Discussion and Analysis -
Liquidity and Capital Resources").
STRATEGY
The Company's strategy is to expand its reserves, production and cash
flow through the implementation of an exploration program that focuses on
(i) obtaining dominant positions in core areas of exploration; (ii) enhancing
the value of the Exploration Projects and reducing exploration risks through
the use of 3-D seismic and CAEX technologies; (iii) maintaining an experienced
technical staff with the expertise necessary to take advantage of the Company's
proprietary 3-D seismic and CAEX seismic data; (iv) reducing exploration risks
by focusing on the identification of potential moderate-depth gas reservoirs,
which the Company believes are conducive to hydrocarbon detection technologies;
and (v) retaining operational control over critical exploration decisions.
OBTAIN DOMINANT POSITION IN CORE AREAS. The Company has identified core
areas for exploration along the Texas and Louisiana Gulf Coasts that
have geological trends with demonstrated histories of prolific natural
gas production from reservoir rocks high in porosity and permeability
with profiles suitable for seismic evaluation. Unlike the Gulf of
Mexico, where 3-D seismic data typically is owned and licensed by many
companies that compete intensely for leases, the private right of
ownership of onshore mineral rights enables individual exploration
companies to proprietarily control the seismic data within focused core
areas. The Company believes that by obtaining substantial amounts of
proprietary 3-D seismic data and significant acreage positions within
its core areas, it will be able to achieve a dominant position in
focused portions of those areas. With such a dominant position, the
Company believes it can better control the core areas' exploration
opportunities and future production, and can attempt to minimize costs
through economies of scale and other efficiencies inherent in its
focused approach. Such cost savings and efficiencies include the
ability to use the Company's proprietary data to reduce exploration
risks and lower its leasehold acquisition costs by identifying and
purchasing leasehold interests only in those focused areas in which the
Company believes exploratory drilling is most likely to be successful.
USE OF 3-D SEISMIC AND CAEX TECHNOLOGIES. The Company attempts to
enhance the value of its Exploratory Projects through the use of 3-D
seismic and CAEX technologies, with an emphasis on direct hydrocarbon
detection technologies. These technologies create computer generated
3-dimensional displays of subsurface geological formations that enable
the Company's explorationists to detect seismic anomalies in structural
features that are not apparent in 2-D seismic surveys. The Company
believes that 3-D seismic technology, if properly used, will reduce
drilling risks and costs by reducing the number of dry holes,
optimizing well locations and reducing the number of wells required to
exploit a discovery. The Company believes that 3-D seismic surveys are
particularly suited to its Exploration Projects along the Texas and
Louisiana Gulf Coasts.
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EXPERIENCED TECHNOLOGICAL TEAM. The Company maintains an experienced
technical staff, including engineers, geologists, geophysicists,
landmen and other technical personnel. After the Acquisitions, the
Company hired most of EPC's technical personnel, who, in some
instances, have worked together for over 15 years. In addition, the
Company has contracts with various geotechnical services consultants
who provide the Company geophysical expertise in managing the design,
acquisition, processing and interpretation of 3-D seismic data in
conjunction with CAEX data.
FOCUSED DRILLING OBJECTIVES. In addition to using 3-D seismic and CAEX
technologies, the Company seeks to reduce exploration risks by
primarily exploring at moderate depths that are deep enough to discover
sizeable gas accumulations (generally 8,000 to 12,500 feet) and that
also are conducive to direct hydrocarbon detection, but not so deep as
to be highly exposed to the greater mechanical risks and drilling costs
incurred in the deep plays in the region. In conjunction with
interpreting the 3-D seismic and CAEX data relating to the Company's
moderate depth wells, the Company anticipates it will identify
potential prospects in deep gas provinces that the Company may elect to
pursue.
CONTROL OF EXPLORATION AND OPERATIONAL FUNCTIONS. The Company believes
that having control of the most critical functions in the exploration
process will enhance its ability to successfully develop its
Exploration Projects. The Company has a majority interest in many of
the Exploration Projects, including proprietary interests in most of
the 3-D seismic data relating to those projects. Although the Company
has partners in the Exploration Projects in which it does not own a
majority interest, in many cases, the Company owns a greater interest
than any of its project partners. As a result, the Company will often
be able to influence the areas to explore, manage the land permitting
and option process, determine seismic survey areas, oversee data
acquisition and processing, prepare, integrate and interpret the data
and identify each prospect drillsite. In addition, the Company will
likely be the operator of most of the wells drilled within the
Exploration Projects.
EXPLORATION PROJECTS
Most of the Exploration Projects are concentrated within the Downdip
Frio, Wilcox and Texas Hackberry core project areas. The Downdip Frio core
area generally is in the middle Texas Gulf Coast where the Company believes
Frio targets exist at moderate depths. The Wilcox core area generally is in
the middle Texas Gulf Coast in an area the Company believes to have prospects
for Wilcox sand exploration. The Texas Hackberry core area is located in
Jefferson and Orange Counties, Texas, in an area which the Company believes
offers drilling opportunities in the Hackberry formations, as well as Miocene
and deeper Vicksburg sands. Other Exploration Projects consist of the
Starboard Project, as well as other projects in Louisiana and Mississippi
that either are in early stage exploration areas that may develop into new
core project areas, or non-core area projects, which are projects that are
not presently expected to be further expanded.
Each of the Exploration Projects differs in scope and character and
consists of one or more types of assets, such as 3-D seismic data, leasehold
positions, lease options, working interests in leases, royalty interests or
other mineral rights. The Company's percentage interest in each Exploration
Project (a "Project Interest") represents the portion of the interest in the
Exploration Project it shares with its other project partners. Therefore, the
Company's Project Interest in an Exploration Project should not be confused
with the working interest that the Company will own when a given well is
drilled. The Company's working interest in the wells on each Exploration
Project may be higher or lower than its Project Interest.
The following table sets forth certain information about each of the
Exploration Projects:
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EXPLORATION PROJECTS
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<CAPTION>
ACRES LEASED OR UNDER
OPTION AT MARCH 26, SQUARE MILES OF
1999(1) 3-D SEISMIC DATA
-------------------------- RELATING TO
PROJECT AREAS GROSS NET PROJECT AREA PROJECT INTEREST(2)
- ------------- ------- ------ ---------------- ------------------
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SOUTH TEXAS
DOWNDIP FRIO CORE AREA
Allen Dome......................... 833 136 -- 50.0%
Gillock............................ 23,804 3,404 82 22.5%
Blessing........................... 1,414 278 22 24.0%
Tidehaven.......................... 3,842 1,254 28 40.5%
El Maton........................... 4,893 1,793 28 46.5%
Midfield........................... 3,267 1,059 21 37.5%
Markham............................ 2,584 1,480 -- 60.0%
Buckeye............................ 20,279 7,667 50 45.0%
Duncan Slough..................... 5,608 1,601 60 40.9%
Southwest Pheasant................. 3,033 1,781 10 75.0%
Geronimo........................... 7,140 1,382 76 20.0%
Houston Endowment.................. 3,000 810 50 27.0%
Wolf Point......................... 960 437 8 45.5%
Sheriff Field...................... 4,943 2,755 -- 75.0%
Bauer Ranch........................ 22,000 4,803 56 33.3%
La Rosa............................ 5,537 443 25 8.0%
Piledriver......................... 640 400 2 62.5%
Archie ............................ 903 207 14 25.0%
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Downdip Frio Sub-Total 114,680 31,690 532
WILCOX CORE AREA
Gila Bend.......................... 1,179 147 16 12.5%
Hall Ranch......................... 7,894 3,266 57 41.5%
Hordes Creek....................... 4,730 1,943 25 41.5%
Mikeska............................ 7,898 2,850 32 38.0%
Duval/McMullen..................... 1,980 1,782 12 90.0%
Verdad............................. 50,994 6,930 57 25.0%
Orangedale......................... 2,353 2,086 3 90.0%
Riverdale.......................... 5,601 1,400 23 25.0%
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Wilcox Sub-Total 82,629 20,404 225
TEXAS HACKBERRY CORE AREA
Lox B.............................. 9,281 1,440 62 25.0%
West Port Acres.................... 881 86 21 12.5%
Big Hill/Stowell................... 7,100 1,960 56 33.3%
Lovells Lake....................... 18,213 4,262 65 33.3%
West Beaumont...................... 1,721 78 23 7.9%
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Texas Hackberry Sub-Total 37,196 7,826 227
LOUISIANA
Lapeyrouse......................... 4,576 943 35 25.0% Average
Crab Lake.......................... 1,130 322 12 75.0%
S. L. Eocene(3).................... 5,516 5,416 -- 100.0%
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Louisiana Sub-Total 11,222 6,681 47
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ACRES LEASED OR UNDER
OPTION AT MARCH 26, SQUARE MILES OF
1999(1) 3-D SEISMIC DATA
-------------------------- RELATING TO
PROJECT AREAS GROSS NET PROJECT AREA PROJECT INTEREST(2)
- ------------- ------- ------ ---------------- ------------------
OTHER TEXAS
Raymondville....................... 27,406 16,210 62 60.4%
Caney Creek........................ 19,759 2,334 33 12.5%
East Texas Pinnacle Reef (4)....... -- -- 400 --
Papalote (3)....................... 25,316 21,685 -- 87.5% Average
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Other Texas Sub-Total 72,481 40,229 495
MISSISSIPPI
Thompson Creek..................... 1,877 1,562 12 93.5%
Lipsmacker......................... 2,892 452 64 22.0%
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Mississippi Sub-Total 4,769 2,014 76
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TOTAL ALL PROJECTS 322,977 108,844 1,602
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(1) Gross acres refers to the number of acres leased or under option in
which the Company owns an undivided interest. Net acres were determined
by multiplying the gross acres leased or under option times the
Company's working interest therein.
(2) Each of the Exploration Projects differs in scope and character and
consists of one or more types of assets, such as 3-D seismic data,
leasehold positions, lease options, working interests in leases,
royalty interests or other mineral rights. The Company's percentage
interest in each Exploration Project (a "Project Interest") represents
the portion of the interest in the Exploration Project it shares with
its other project partners. Therefore, the Company's Project Interest
in an Exploration Project should not be confused with the working
interest that the Company will own when a given well is drilled. The
Company's working interest in the wells on each Exploration Project may
be higher or lower than its Project Interest.
(3) Proprietary 3-D seismic data is planned to be shot over these areas in
the near future.
(4) Consists of 400 square miles of 3-D seismic data to which Aspect has
rights pursuant to a license agreement, and to which the Company may
acquire an interest pursuant to a geophysical technical services
agreement with Aspect.
EXPLORATION PROJECT DESCRIPTIONS. Set forth below is a description of
the Exploration Projects. The amounts specified for the interests in the
Exploration Projects and gross and net acreage of each Exploration Project and
the project description were determined as of March 26, 1999. Estimates of
drilling and completion costs are gross amounts and are not necessarily net to
the Company's interests in the related Exploration Projects. In addition,
predictions of well costs are estimates only, and actual costs may vary based
on, among other factors, down hole conditions and costs for drilling rigs at the
time of drilling. In prospects where 3-D seismic surveys are not yet shot,
processed and interpreted, such data may, when available, enhance or condemn
previously identified prospects or leads.
DOWNDIP FRIO CORE AREA PROJECTS
ALLEN DOME. The Allen Dome Project consists of leases and options of
approximately 833 gross acres with 271 net acres in Brazoria County, Texas. The
Company has a 50% Project Interest with 136 net acres to its interest. The
acreage targets the Frio "A" Sands and is updip from a show in the Frio "A"
Sand. Miocene potential exists in radial fault traps surrounding the dome. A
spec shoot is in the planning stage, and the Company is attempting to tie onto
the larger Speculative shoot in the area. A minimal amount of data will be
needed to image the trap. Estimated drilling and completion costs for the deep
Frio test is $1.2 million.
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GILLOCK. The Gillock Project consists of leases and options covering
approximately 23,804 gross acres with 15,129 net acres in Galveston County,
Texas, which also includes HBP leasehold. The Company has a 22.5% Project
Interest in this 3-D seismic project with 3,404 net acres to its interest. The
primary geological targets the Company has identified, for potential drilling,
are the Frio and Vicksburg Sands. A 70 square mile 3-D survey was completed in
July 1998, has been processed, and is currently being interpreted. Preliminary
interpretations have yielded several low risk prospects in the project area. The
estimated cost to drill and complete a shallow well is approximately $900,000,
with deeper wells costing over $3.5 million.
BLESSING. The Blessing Project consists of leases and options covering
approximately 1,414 gross acres with 1,157 net acres under 22 square miles of
3-D seismic coverage in Matagorda County, Texas. The Company has a non-operated
24.0% Project Interest with 278 net acres to its interest. A 3-D seismic survey
was conducted in conjunction with the Tidehaven 3-D shoot (see "Tidehaven
Project"). The Operator has drilled two (2) Upper Frio Sand wells. One well
produced 277 MMCF per day and 4,267 BC per day in 1998, and has been recompleted
in another pay zone, which is currently producing 1400 MCF per day and 20 BC per
day; the other well was a dry hole. The Company's Working Interest in the well
is 33.935%, although the Company's Project Interest in the remaining portion of
the project is 24.0%. No wells are planned for 1999. The estimated cost of
drilling and completing a shallow well in this project area is approximately
$550,000.
TIDEHAVEN. The Tidehaven Project consists of leases and options
covering over 3,842 gross acres with 3,097 net acres in Matagorda County, Texas.
The Company has a 40.5% Project Interest with 1,254 net acres to its interest.
These leases overlay a series of known field pays and multiple fault blocks,
which made this structure a 3-D seismic candidate. Initial interpretation of the
28 square mile 3-D seismic data set is complete. The Company has drilled and
completed two wells in the lower Frio. The first is currently producing 1.1 MMCF
per day and 7 BC per day, and the other was a dry hole. The estimated cost to
drill and complete a well ranges from approximately $550,000 to $1.5 million,
depending upon depth. There are several additional Mid Frio and Lower Frio
prospects.
EL MATON. The El Maton Project consists of leases and options covering
approximately 4,893 gross acres with 3,856 net acres in Matagorda County, Texas.
The Company has a 46.5% Project Interest with 1,793 net acres to its interest. A
29 square mile 3-D seismic survey was started in May 1997, as an extension of
the Tidehaven shoot. This seismic survey has been completed and the
interpretation is essentially complete. The geologic setting and target zones
are the same as for Tidehaven. The Company has merged the 3-D data sets in the
El Maton, Tidehaven, Blessing, and Midfield projects. The Company has identified
several Mid Frio and Lower Frio prospect leads. The estimated cost to drill and
complete a well ranges from approximately $550,000 to $1.5 million, depending
upon depth.
MIDFIELD. The Midfield Project consists of leases and options covering
approximately 3,267 gross acres with 2,825 net acres in Matagorda County, Texas.
The Company has a 37.5% Project Interest with 1,059 net acres to its interest.
The project is an extension of the Tidehaven, Blessing and El Maton 3-D seismic
shoots. All four of these 3-D seismic surveys have been merged. The Midfield
Project is adjacent to and up basin from, the Tidehaven Project. The geologic
setting and target zones are similar to Tidehaven. Initial data interpretation
on a 21 square mile 3-D seismic survey over this acreage is complete, and the
data has revealed two (2) low risk shallow drilling locations. The estimated
cost to drill and complete a shallow well is approximately $550,000.
MARKHAM. The Markham Project consists of leases and options covering
approximately 2,584 gross acres with 2,466 net acres in Matagorda County, Texas.
The Company has a 60% project interest with 1,048 net acres to its interest. The
3-D has been completed, and the Company is interpreting the data. Initial review
of the seismic is encouraging and several prospects have been identified. The
estimated costs to drill and complete a shallow well is approximately $550,000,
with deeper well costing approximately $1.3 million.
BUCKEYE RANCH. The Buckeye Ranch Project consists of approximately
20,279 gross acres with 17,037 net acres of lease options in Matagorda County,
Texas. The Company has a 45% Project Interest with 7,667 net acres to its
interest. A 3-D seismic survey has been completed, and the Company is currently
interpreting the data. The estimated cost to drill and complete a shallow well
is approximately $550,000, with deeper wells costing approximately $1.3 million.
Initial review of the seismic data is encouraging and numerous prospects have
been delineated.
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DUNCAN SLOUGH. The Duncan Slough Project consists of leases and options
covering approximately 5,608 gross acres with 3,906 net acres in Matagorda
County, Texas. The Company has a 40.99% Project Interest with 1,601 net acres to
its interest. The 3D survey has been completed, and the Company is interpreting
the data. Initial review of the seismic is encouraging and numerous prospects
have been delineated. The estimated cost to drill and complete a shallow well is
approximately $550,000, with deeper wells costing approximately $1.3 million.
The Company is planning to merge the Markham-Buckeye-Duncan Slough 3-D data with
the adjacent surveys.
SOUTHWEST PHEASANT. The Southwest Pheasant Project consists of leases
and options covering approximately 3,033 gross acres with 2,375 net acres in
Matagorda County, Texas. The Company has a 75.0% Project Interest with 1,781 net
acres to its interest. The primary geological objectives are the middle and
lower Frio sands. A portion of the project area is covered by an old Mobil 3-D
seismic that has been reprocessed and reinterpreted. The Company has identified
several shallow prospects. The estimated cost to drill and complete a shallow
well is approximately $550,000, with deeper wells costing approximately $1.3
million.
GERONIMO. The Geronimo Project consists of leases and options covering
approximately 7,140 gross acres with 6,911 net acres in San Patricio County,
Texas. The Company has a 20% Project Interest with 1,382 net acres to its
interest. A 76 square mile 3-D seismic survey has been shot, and the Company has
identified several prospective drillsites. One well has been drilled and is
producing 50 BO per day and 142 MCF per day. A deep Vicksburg test and an
Anderson Sand test well are currently being marketed. The estimated cost to
drill and complete a well is approximately $600,000 for a shallow well, $1.2
million for an intermediate depth well, and $4.0 million for a Vicksburg well.
HOUSTON ENDOWMENT. The Houston Endowment Project consists of leases and
options covering approximately 3,000 gross acres with 3,000 net acres in San
Patricio and Aransas Counties, Texas. The Company has a 27.0% Project Interest
with 810 net acres to its interest. A 50 square mile 3-D seismic survey has been
acquired. Esenjay Petroleum Corporation drilled one dry hole within the project
area before execution of the Acquisition Agreement. The Company drilled an
additional Deep Frio test, which was not successful. The estimated cost to drill
and complete a shallow well is approximately $700,000 with deeper wells costing
approximately $1.3 million.
WOLF POINT. The Wolf Point Project consists of state leases covering
approximately 960 gross acres with 960 net acres in Calhoun County, Texas. The
Company has a 45.5% Project Interest with 437 net acres to its interest. Esenjay
Petroleum Corporation drilled and completed two (2) successful wells within the
3-D seismic survey area before the Effective Date of the Acquisitions (November
1, 1997). Known field pays from this area are the 7,200-foot Frio, 7,500-foot
Frio, 7,700 foot Frio, Broughton, Oats, Upper, Middle and Lower Melbourne sands.
The Company drilled one successful well which is currently producing
approximately 1.3 MMCF per day and 13 BC per day. The Company has also drilled
one dry hole. The estimated cost to drill and complete a well is approximately
$900,000.
SHERIFF FIELD. The Sheriff Project consists of approximately 4,943
gross acres with 3,674 net acres of lease options in Calhoun County, Texas. The
Company has a 75.0% Project Interest with 2,755 net acres to its interest. The
Company has written off most of the book value of this project and does not
expect it to play a significant part in its near term exploration activities.
BAUER RANCH. The Bauer Ranch Project contains approximately 22,000
gross acres with 14,411 net acres of lease options in Jefferson County, Texas.
The Company has a 33.33% Project Interest with 4,803 net acres to its interest.
Numerous prospect leads have been generated within the area via log shows,
detailed structural mapping, and 2-D seismic data. Deep exploration zones also
are targeted. The Company recently completed shooting a 56 square mile 3-D
seismic survey and is currently interpreting the data. The estimated cost to
drill and complete a shallow well is approximately $650,000, with deeper wells
costing approximately $1.6 million.
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LA ROSA. The La Rosa Project consists of approximately 5,537 gross
acres with 5,537 net acres of leases and options in Refugio County, Texas. The
Company has non-operating Project Interest of between 8.0% and 13% with between
443 and 719 net acres to its interest. A 25 square mile 3-D seismic shoot has
been acquired and interpreted. Four wells have been drilled since the Effective
Date of the Acquisition for the Company's account. Three wells were dry holes.
The most recent well is currently producing 440 MCF per day. The Company has a
13% interest in this well. The estimated cost to drill and complete a Frio
formation well is approximately $450,000.
PILEDRIVER. The Piledriver Project consists of 640 gross acres and 640
net acres of state leases located in Chambers County, Texas. The Company has a
62.5% Project Interest with 400 net acres to its interest. The objectives are
two Frio age sands. One of these target sands has what the Company believes to
be a significant gas test at the top of the sand in a well that it believes is
down dip to the Company's acreage. A 3D seismic survey was recently conducted by
Western Geophysical. The Company has acquired the data and is interpreting it at
this time before making any drilling decisions. The estimated cost to drill and
complete a well is approximately $1.85 million.
ARCHIE. The Archie Project consists of leases covering 903 gross acres
and 826 net acres located in Chambers County, Texas. The Company owns a 25%
project interest with 207 net acres to its interest. Interpretations of the 13.4
square mile 3-D are complete and the location on the first of three low risk
prospects is being built. The target zones are the lower Frio Textularia
Mississippiensis sands. Estimated dry hole costs are $800,000.
WILCOX CORE AREA PROJECTS
GILA BEND. The Gila Bend Project consists of a continuous acreage block
of 1,179 gross acres with 1,179 net acres under a 16 square mile 3-D in Karnes
County, Texas. The Company has a 12.5% interest with 147 net acres to its
interest. The project is adjacent to the Company's Hall Ranch and Verdad
projects. The 3-D interpretation is complete, and a deviated well is scheduled
in the second quarter of 1999, to test multiple Wilcox Sands. The estimated cost
to drill and complete a deviated well, in the deep Wilcox, is approximately $3.0
million.
HALL RANCH. The Hall Ranch Project consists of leases and options
covering approximately 7,894 gross acres with 7,869 net acres under a 57 square
mile 3-D seismic survey in Karnes County, Texas. The Company has a 41.5% Project
Interest with 3,266 net acres to its interest. The Company believes the Hall
Ranch area is on an under-explored ridge on trend with several producing fields.
Multiple potential pay zones in four expanded fault blocks have been delineated
in the Wilcox sands from approximately 8,000 to 17,000 feet. Known field pays
are from Wilcox reservoirs in the Migura, Roeder, Bunger, Hackney, Middle Wilcox
L series sands, and the Upper Wilcox. The Company has delineated several
potential drill sites. The Company has drilled and run production casing on its
first well on this project. The well is currently producing 5 MMCF per day
without any production decline over the last 6 months. This well was drilled at
a location in which the Company owns a 20.75% non-operated Working Interest. The
Company will own and operate 41.5% Working Interest in offset locations. The
estimated cost to drill and complete a well ranges from approximately $270,000
to $600,000 for shallow wells, while wells completed in the deep zones (to
12,500 feet) cost approximately $2.0 million.
HORDES CREEK. The Hordes Creek Project contains leases and options on
approximately 4,730 gross acres with 4,683 net acres located in Goliad County,
Texas. The Company has a 41.5% Project Interest with 1,943 net acres to its
interest. The Company believes Hordes Creek has potential in the Miocene, Frio,
Yegua, and the Upper, Middle, and Lower Wilcox Sands. Preliminary migrated 3-D
seismic data covering 25 square miles has been interpreted. The Company has
drilled two shallow Wilcox wells in the project, both of which were dry holes. A
deep Wilcox (15,000 ft.) test is currently being marketed. A shallow Yegua well
is in the planning stage. The estimated cost to drill and complete a shallow
Yegua well is approximately $355,000.00. The estimated cost to drill and
complete a deep Wilcox test is $2.9 million.
MIKESKA. The Mikeska Project consists of leases covering approximately
7,898 gross acres with 7,500 net acres located in Live Oak County, Texas. The
Company has a 38.0% Project Interest with 2,850 net acres to its interest.
Multiple pay potential exists from 8,500 feet to at least 16,000 feet. This
portion of the Wilcox trend contains known pays from the Hockley, four Queen
City sands, four Slick sands, six Luling sands, three Tom Lyne sands and three
to five House sands. A 32 square mile 3-D seismic survey has been shot and the
data has been
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recently reprocessed and is being reinterpreted. One well has been
drilled and completed as a low volume oil well and is not an impact well. A
second well has been completed and tested 9 MMCF per day plus water, and is
awaiting pipeline connection. The Company has identified several drill sites
updip to the discovery well. The estimated cost to drill and complete a shallow
well is approximately $800,000, with deeper wells costing approximately $1.4
million.
DUVAL/MCMULLEN. The Duval/McMullen Project consists of approximately
1,980 gross acres with 1,980 net acres of options in Duval and McMullen
Counties, Texas. The Company has a 90.0% Project Interest with 1,782 net acres
to its interest. The Company is negotiating with Western Geophysical to acquire
a one-year-old proprietary 3-D seismic survey. The Company plans to interpret
the 3-D seismic data before drilling. The estimated cost to drill and complete a
shallow well is approximately $800,000, with deeper wells costing approximately
$1.2 million. These leases have not been available prior to the 3D seismic data
being acquired and released. Vastar Resources has recently enjoyed significant
drilling success adjacent to Esenjay's acreage.
VERDAD. The Verdad Project consists of leases and options covering
approximately 50,994 gross acres with 27,721 net acres under a 40 square mile
3-D seismic survey in Karnes County, Texas. The Company owns a non-operated 25%
interest in this project with 6,930 net acres to its interest. Verdad has
potential pays in the shallow Frio, Yegua, and Upper Wilcox, as well as the
upside potential in the numerous Middle and Lower Wilcox reservoirs. This
project is adjacent to the Company's Hall Ranch Project. The Company expects to
begin interpreting data in mid April 1999. Estimated drilling and completed well
costs in the project area range from approximately $270,000 to $600,000 for
shallow wells, while wells completed in the deep zones cost approximately $1.8
million.
ORANGEDALE. The Orangedale Project consists of approximately 2,353
gross acres with 2,318 net acres of leases in Bee County, Texas. The Company has
a 90% interest with 2,086 net acres to its interest. The prospect was originally
a subsurface idea backed up by 2-D data and then was recently shot as a large
spec 3-D shoot by a third party. Esenjay has rights to and has interpreted three
square miles of the 3-D data. Seitel has recently shot another 3-D survey, which
will overlap the survey shot by Edge in 1997, and will also cover additional
Esenjay leases not previously shot. Multiple pay potential exists from 8,800' to
15,000' in the expanded Upper and Middle Wilcox Sands. Wells required to test
the several proposed traps from a depth of 10,150' (non-pipe) to 15,000', cost
from $450,000 to $1,500,000, respectively.
RIVERDALE. The Riverdale Project consists of a continuous acreage block
of 5,601 gross acres with 5,601 net acres in a complexly faulted area ten miles
west of Goliad, Texas. The Company has a 25% non-operated interest with 1,400
net acres to its interest. The Frio, Vicksburg, Hockley, Yegua, Cook Mountain
and Upper Wilcox sands from depths of 1700' to 9500' have all produced in the
immediate area and are considered to be prospective. Large untested fault blocks
have been mapped in the area using approximately 100 miles of 2-D seismic in
conjunction with the available well control. Recently Western Geophysical has
acquired 3-D data across this project and the Company is interpreting the data.
This area is adjacent to and will be merged with the Company's Hordes Creek
project. The estimated cost to drill and complete a 9500' test is approximately
$800,000.
TEXAS HACKBERRY CORE AREA PROJECTS
LOX B. The Lox B Project consists of 9,281 gross acres with 5,759 net
acres of leases and options in Jefferson County, Texas. The Company has a 25.0%
non-operated Project Interest with 1,440 net acres to its interest. The primary
objectives of this project are the Hackberry and Vicksburg formations. The
acreage has been evaluated with 71 square miles of 3-D seismic data. The Company
has identified numerous potential prospects through the use of seismically
detected hydrocarbon indicators. The 3-D seismic survey has been merged with the
West Port Acres data, and ultimately will be merged with the Big Hill/Stowell
and Lovells Lake 3-D seismic surveys described below. The initial well was dry
and the second well appears to be a significant discovery. The operator, H.S.
Resources, Inc. anticipates flowing the well at 15 MMCF per day and 750 BC per
day. The estimated cost to drill and complete a Hackberry well is approximately
$1.3 million, and Vicksburg wells cost approximately $1.8 million to drill and
complete.
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WEST PORT ACRES. The West Port Acres Project consists of 881 gross
acres with 686 net acres of leases in Jefferson County, Texas, which have
been acquired and a 21 square mile 3-D seismic survey has been conducted. The
Company has a 12.5% non-operated Project Interest with 86 net acres. The
Company has identified several Hackberry prospects. The estimated cost to
drill and complete a Hackberry well is approximately $1.5 million.
BIG HILL/STOWELL. The Big Hill/Stowell Project consists of over
7,100 gross acres with 5,882 net acres of leases and options in Jefferson
County, Texas. The Company has a 33.33% Project Interest with 1,960 net acres
to its interest. The Company has entered an agreement to sell all of its
undeveloped property interests in the Big Hill/Stowell area to Helmerich &
Payne, Inc.
LOVELLS LAKE. The Lovells Lake Project consists of 18,213 gross
acres with 12,788 net acres of leases and options in Jefferson County, Texas.
The Company has a 33.33% Project Interest with 4,262 net acres to its
interest. The Company has completed a 65 square mile 3-D seismic survey,
which has been interpreted, yielding numerous Hackberry prospects. The
Company has drilled and logged 58 feet of net gas pay in the first well and
is awaiting completion. A second well is currently being drilled. The Company
anticipates drilling four additional wells in 1999. The estimated cost to
drill and complete a Hackberry well ranges from approximately $1.0 million to
$1.5 million.
WEST BEAUMONT. The West Beaumont Project consists of 1,721 gross
acres with 990 net acres of leases and options in Jefferson County, Texas.
The Company has a 7.9% non-operated Project Interest with 80 net acres to its
interest. A 22.5 square mile 3-D seismic survey has been interpreted by the
Company. Several Frio and Hackberry age prospects have been identified. Two
wells have been drilled by the operator. The first well tested at 1.1 MMCF
per day and 403 BO per day. The second well has been drilled and pipe has
been set awaiting completion. The estimated cost to drill and complete a
Hackberry well is approximately $750,000. The Company has entered a contract
to sell its undeveloped property interests in this project.
LOUISIANA PROJECTS
LAPEYROUSE. The Company has non-operated working interests in the
leases over this project ranging from 12.0% to 46.875%, depending upon the
target formation depths. The project consists of approximately 4,576 gross
and 3,772 net acres of leases in the Lapeyrouse Field in Terrebonne Parish,
Louisiana. The 3-D seismic data has been shot, processed and interpreted.
After seismic interpretation, two exploratory initial wells have been
identified. Both wells will expose the Company to significant reserve
potential in a trend area where numerous giant oil and gas fields are
located. Drilling is expected to commence in the fourth quarter of 1999. The
estimated cost to drill and complete a well is approximately $3.2 million to
$5.5 million depending upon depth.
CRAB LAKE. The Company has retained a 75% project interest, which
consists of 1,130 gross and 429 net acres of leases in Cameron Parish,
Louisiana. The primary target objectives are in the Miocene series of sands.
The Company has interpreted a 12 square mile 3-D seismic shoot, part of a
52 square mile 3-D. The first well is scheduled to be drilled in third
quarter 1999, as a development well to extend the field. The well will test
multiple objectives, and if successful, will require further development
drilling. The estimated cost to drill and complete a well is approximately
$1.1 million.
S. L. EOCENE. The S. L. Eocene Project contains approximately 5,516
gross acres with 5,416 net acres of lease options in Beauregard Parish,
Louisiana. The Company has a 100.00% Project Interest with 5,416 net acres.
Numerous project leads have been generated within the area via log shows,
detailed facies mapping, and 2-D seismic data. The main target horizon for
this project is the Cockfield Formation. The shallower frio and deeper Wilcox
zones may also be targeted. The Company is currently marketing the project to
potential partners. The estimated cost to drill a Cockfield well is $275,000,
with a completed well cost estimated at $450,000.
OTHER TEXAS PROJECTS
RAYMONDVILLE. The Raymondville Project consists of approximately
27,406 gross acres with 26,849 net acres of leases and options in Willacy
County, Texas. The Company has a 60.37500% Project Interest with 16,210 net
acres to its interest. This project includes separate geologic structures
known by four different field names. The pre 3-D seismic geologic study of
this area has identified several possible drilling locations. These locations
were
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selected based on subsurface well correlation and production analysis. A
62 square mile 3-D seismic survey has been acquired and currently is in
processing. The Company anticipates to begin interpreting the data in
May 1999. Two of the locations, which were identified by subsurface mapping
prior to 3D seismic, have been drilled. Both have logged multiple pay zones
and both have been completed as dual gas producers. The combined initial flow
rate for the wells exceeded 10 MMCF per day, and they are currently producing
6 MMCF per day. The Company has recently sold an 18.5% working interest for
$3.76 million. The estimated cost to drill and complete a well is
approximately $550,000.
CANEY CREEK. The Caney Creek Project consists of options and leases
covering 19,759 gross acres with 18,670 net acres in Matagorda and Wharton
Counties, Texas. The Company has a 12.5% Project Interest with 2,334 net
acres to its interest. The project targets the Frio and Yegua reservoirs. A
32 square mile 3-D seismic survey has been conducted, and the interpretation
of the data has been completed. Several leads have been identified. The
Company entered a contract to sell its undeveloped interests in this area.
EAST TEXAS PINNACLE REEF TREND. Aspect and certain of its affiliates
have licenses covering approximately 400 square miles of 3-D seismic data
pertaining to the East Texas Cotton Valley Reef Trend. This seismic data is
recently acquired and most of it is proprietary. Currently, there is no
acreage position or defined drilling opportunity associated with this project.
The Company intends to enter into a joint venture with Aspect or its
affiliates to attempt to generate drillable prospects. The joint venture
will, if consummated, be subject to the terms of any licensing or other
agreements currently in effect.
PAPALOTE. The Papalote Project consists of leases and options of
approximately 25,316 gross acres with 24,783 net acres in San Patricio and
Bee Counties, Texas. The Company has ownership of between 75% and 100% in the
Project at various stages in the development of the property. A +100 square
mile 3-D is planned for 1999. The project will target the Frio sands with the
Vicksburg Sands as a secondary target, and the Yegua formation as the primary
exploratory target. Several Yegua leads have been identified with subsurface
and 2-D seismic. A Frio/Vicks well will cost $250,000 to drill and complete
and a Yegua well will cost approximately $1.0 million.
MISSISSIPPI PROJECTS
THOMPSON CREEK. The Thompson Creek Project consists of approximately
1,877 gross acres with 1,671 net acres of leases and options in Wayne County,
Mississippi. The Company has a 93.5% Project Interest with 1,562 net acres to
its interest. Approximately 12 miles of 3D have been interpreted along the
salt ridge. The Company has written off most of the book value of this
project and does not expect it to play a significant part in its near term
exploration activities.
LIPSMACKER. The Lipsmacker Project consists of approximately 2,892
gross acres with 2,056 net acres of leases and options in Choctaw, Alabama
and Clarke Counties, Mississippi. The Company has a 22.0% Project Interest
with 452 net acres to its interest. Esenjay Petroleum Corporation completed a
64 square mile 3-D seismic survey in the fall of 1996, and while several
drilling locations were tested, the results generally were disappointing. The
Company believes there is one additional well to be drilled. The Company is
currently marketing this prospect. The estimated cost to drill and complete a
well is approximately $1.2 million.
CAEX TECHNOLOGY AND 3-D SEISMIC
The Company, either directly or through its partners, uses CAEX
technology to collect and analyze geological, geophysical, engineering,
production and other data obtained about potential gas or oil prospects. The
Company uses this technology to correlate density and sonic characteristics
of subsurface formations obtained from 2-D seismic surveys with like data
from similar properties, and uses computer programs and modeling techniques
to determine the likely geological composition of a prospect and potential
locations of hydrocarbons.
Once all available data has been analyzed to determine the areas
with the highest potential within a prospect area, the Company may conduct
3-D seismic surveys to enhance and verify the geological interpretation of
the structure, including its location and potential size. The 3-D seismic
process produces a three-dimensional image based upon seismic data obtained
from multiple horizontal and vertical points within a geological formation.
The
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calculations needed to process such data are made possible by computer
programs and advanced computer hardware.
While large oil companies have used 3-D seismic and CAEX
technologies for approximately 20 years, these methods were not affordable by
smaller, independent gas and oil companies until more recently, when improved
data acquisition equipment and techniques and computer technology became
available at reduced costs. The Company began using 3-D seismic and CAEX
technologies in 1992 and is using these technologies on a continuing basis.
The Company believes its use of CAEX and 3-D seismic technology may provide
it with certain advantages in the exploration process over those companies
that do not use this technology. These advantages include better delineation
of the subsurface, which can reduce exploration risks and help optimize well
locations in productive reservoirs. The Company believes these advantages can
be readily validated based upon general industry experience as well as the
experiences of Aspect and EPC. Because computer modeling generally provides
clearer and more accurate projected images of geological formations, the
Company believes it is better able to identify potential locations of
hydrocarbon accumulations and the desirable locations for wellbores. However,
the Company has not used the technology extensively enough to arrive at any
conclusion regarding the Company's ability to interpret and use the
information developed from the technology.
EXPLORATION AND DEVELOPMENT
The Company considers the Gulf Coast to be the premier area in the
United States to explore for significant new reserves. This conclusion is
based on several characteristics including (i) a large number of productive
intervals throughout a significant sedimentary section, (ii) numerous wells
with which to calibrate 3-D seismic data and (iii) complicated geological
formations that the Company believes 3-D seismic technology is particularly
well suited to interpretation. In 1994, the Company began devoting more of
its energy to the Gulf Coast region. The Company initially entered this area
by evaluating the onshore shallow Frio/Miocene Trend. Its emphasis expanded
to include larger exploration targets represented by large geological
features such as those present in the Starboard Project. Upon completion of
the Acquisitions, the Company spread its focus over an array of exploration
projects along the Gulf Coast and intends to expand its project inventory in
these areas. The Company's Exploration Project inventory is along the Gulf
Coast of Texas, Louisiana, Alabama and Mississippi. The focus is on natural
gas exploration prospects with a numerical concentration along the Texas Gulf
Coast, many of which were delineated by seismic hydrocarbon indicators.
Additional 2-D and 3-D seismic surveys may be required to evaluate these
areas more fully, and when determined appropriate, the Company intends to
acquire acreage and drill wells as indicated by the evaluations.
The Company intends to drill prospects where the formations being
tested are known to be productive in the general area and where it believes
3-D seismic can be used to increase resolution and thereby reduce risk. The
extent to which the Company will pursue its activities in the onshore Gulf
Coast region will be determined by the availability of the Company's
resources and the availability of joint venture partners.
ACQUISITIONS AND DIVESTMENTS
The Company has periodically acquired producing natural gas and
oil properties. In connection with each acquisition, the Company considers
(i) current and historic production levels and reserve estimates,
(ii) additional exploration and exploitation potential via technology
enhancements; (iii) capital requirements; (iv) proximity of product markets;
(v) regulatory compliance; (vi) acreage potential; and (vii) existing
production transportation capabilities. The Company also considers the
historic financial operating results and cash flow potential of each
acquisition opportunity. Evaluation of the merits of a particular acquisition
is based, to the extent relevant, on all of the above factors as well as
other factors deemed relevant by the Company's management.
The Company has currently de-emphasized its producing property
acquisition activities. The Company intends to limit its near term producing
property acquisitions to opportunities that facilitate its exploration
activities. The Company may readdress this approach if it identifies an
opportunity it believes to be of exceptional benefit to its shareholders.
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HEDGING ACTIVITIES AND MARKETING
The Company markets its natural gas through monthly spot sales.
Because sales made under spot sales contracts result in fluctuating revenues
to the Company depending upon the market price of gas, the Company may enter
into various hedging agreements to minimize the fluctuations and the effect
of price declines or swings. During January 1999, the Company completed
performance on a 1996 swap agreement on approximately 1,040 MMBtu's per day
of Mid-Continent natural gas production for $1.566 per MMBtu for the period
beginning April 1, 1996 and ending January 31, 1999.
In October of 1998, the Company entered into two swap agreements,
one for 4,000 MMBtu's per day of its Gulf Coast natural gas production for
$2.14 per MMBtu for the period beginning November 1998 and ending in October
1999, and the second one for 700 MMBtu's per day of its Gulf Coast natural
gas production for $2.13 per MMBtu for the period beginning November 1998 and
ending in October 1999. Both of these swap agreements were supplemented in
December 1998 when the Company entered into additional swap agreements, one
of which was for 4,000 MMBtu's per day of its Gulf Coast natural gas
production for $2.07 per MMBtu for the period beginning November 1999 and
ending in October 2000, and the second one was for 700 MMBtu's per day of its
Gulf Coast natural gas production for $2.07 per MMBtu for the period
beginning November 1999 and ending in October 2000. As a result of the
foregoing transactions, the Company has 4,700 MMBtu's per day of its Gulf
Coast natural gas production hedged through October 2000.
The Company expects that its daily production will continue to
increase rapidly and it will periodically consider additional hedge
transactions consistent with its ongoing policy. Its policy is to
periodically review its projected natural gas production from proved
developed properties in light of then current market conditions. Its
objective is to seek to prudently stabilize its future cash flows from proven
producing properties. It believes that as it continues to expand its drilling
budget this methodology allows it to have more control over its short-term
cash flow while not giving up the upside potential in its future revenues, a
substantial portion of which it projects to be from properties within its
project inventory which are yet to be drilled.
All of the Company's oil production is now sold under
market-sensitive or spot price contracts. The Company's revenues from oil
sales fluctuate depending upon the market price of oil. No purchaser
accounted for more than 10% of the Company's total revenue in 1997 or 1998.
The Company does not believe the loss of any existing purchaser would have a
material adverse effect on the Company.
The Company has a credit facility with Duke Energy Field Services,
Inc., which allows the lender the right to gather, process, transport and
market, at competitive market rates, natural gas produced from a majority of
the Exploration Projects through December 31, 2005.
OPERATING HAZARDS AND INSURANCE
The gas and oil business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations, and environmental hazards such as oil spills, gas
leaks, ruptures or discharges of toxic gases, the occurrence of any of which
could result in substantial losses to the Company due to injury or loss of
life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, cleanup responsibilities,
regulatory investigation and penalties and suspension of operations.
The Company maintains a gas and oil lease operator insurance policy
that insures the Company against certain sudden and accidental risks
associated with drilling, completing and operating its wells. There can be no
assurance that this insurance will be adequate to cover any losses or
exposure to liability. The Company also carries comprehensive general
liability policies and an umbrella policy. The Company and its subsidiaries
carry workers' compensation insurance in all states in which they operate.
The Company maintains various bonds as required by state and federal
regulatory authorities. Although the Company believes these policies are
customary in the industry, they do not provide complete coverage against all
operating risks. An uninsured or partially insured claim, if successful and
of sufficient magnitude, could have a material adverse effect on the Company
and its financial condition. If the Company experiences significant claims or
losses, the Company's insurance premiums could be increased which may
adversely affect the Company and its financial condition or limit the ability
of the Company to
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obtain coverage. Any difficulty in obtaining coverage may impair the
Company's ability to engage in its business activities.
REGULATION
GENERAL. The gas and oil industry is extensively regulated by
federal, state and local authorities. In particular, gas and oil production
operations and economics are affected by price controls, environmental
protection statutes, tax statutes and other laws and regulations relating to
the petroleum industry, as well as changes in such laws, changing
administrative regulations and the interpretations and application of such
laws, rules and regulations. Gas and oil industry legislation and agency
regulation are under constant review for amendment and expansion for a
variety of political, economic and other reasons. Numerous regulatory
authorities, federal, and state and local governments issue rules and
regulations binding on the gas and oil industry, some of which carry
substantial penalties for failure to comply. The regulatory burden on the gas
and oil industry increases the Company's cost of doing business and,
consequently, affects its profitability. The Company believes it is in
compliance with all federal, state and local laws, regulations and orders
applicable to the Company and its properties and operations, the violation of
which would have a material adverse effect on the Company or its financial
condition.
SEISMIC PERMITS. Current law in the State of Louisiana requires
permits from owners of at least an undivided 80% interest in each tract over
which the Company intends to conduct seismic surveys. As a result, the
Company may not be able to conduct seismic surveys covering its entire area
of interest. Moreover, 3-D seismic surveys typically are conducted from
various locations both inside and outside the area of interest to obtain the
most detailed data of the geological features within the area. To the extent
that the Company is unable to obtain permits to access locations to conduct
the seismic surveys, the data obtained may not be as detailed as might
otherwise be available.
EXPLORATION AND PRODUCTION. The Company's operations are subject to
various regulations at the federal, state and local levels. Such regulations
include (i) requiring permits for the drilling of wells; (ii) maintaining
bonding requirements to drill or operate wells; and (iii) regulating the
location of wells, the method of drilling and casing wells, the surface use
and restoration of properties upon which wells are drilled, the plugging and
abandoning of wells and the disposal of fluids used in connection with well
operations. The Company's operations also are subject to various conservation
regulations. These include the regulation of the size of drilling and spacing
units, the density of wells that may be drilled, and the unitization or
pooling of gas and oil properties. In addition, state conservation laws
establish maximum rates of production from gas and oil wells, generally
prohibiting the venting or flaring of gas, and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amount of gas and oil the Company can produce from its wells and to
limit the number of wells or the locations at which the Company can drill.
Recently enacted legislation and regulatory action in Texas and Oklahoma is
intended to reduce the total production of natural gas in those states.
Although such restrictions have not had a material impact on the Company's
operations to date, the extent of any future impact therefrom cannot be
predicted.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION. Federal
legislation and regulatory controls in the United States have historically
affected the price of the natural gas produced by the Company and the manner
in which such production is marketed. The transportation and sale for resale
of natural gas in interstate commerce are regulated by the Federal Energy
Regulatory Commission ("FERC") pursuant to the Natural Gas Act and the
Natural Gas Policy Act of 1978 ("NGPA"). The maximum selling prices of
natural gas were formerly established pursuant to regulation. However, on
July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol
Act") was enacted, which terminated wellhead price controls on all domestic
natural gas on January 1, 1993 and amended the NGPA to remove completely by
January 1, 1993 price and nonprice controls for all "first sales" of natural
gas, which will include all sales by the Company of its own production.
Consequently, sales of the Company's natural gas currently may be made at
market prices, subject to applicable contract provisions. The FERC's
jurisdiction over natural gas transportation was unaffected by the Decontrol
Act.
The FERC also regulates interstate natural gas transportation rates
and service conditions, which affect the marketing of natural gas produced by
the Company, as well as the revenues received by the Company for sales of
such natural gas. Since the latter part of 1985, the FERC has endeavored to
make interstate natural gas transportation more accessible to gas buyers and
sellers on an open and nondiscriminatory basis. The FERC's efforts have
16
<PAGE>
significantly altered the marketing and transportation of natural gas.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (collectively, "Order No. 636"), which, among other things, require
interstate pipelines to "restructure" their services to provide
transportation separate or "unbundled" from the pipelines' sales of gas.
Also, Order No. 636 requires interstate pipelines to provide open-access
transportation on a nondiscriminatory basis that is equal for all natural gas
shippers. Order No. 636 has been implemented through decisions and negotiated
settlements in individual pipeline services restructuring proceedings. In
many instances, the result of Order No. 636 and related initiatives has been
to substantially reduce or eliminate the interstate pipelines' traditional
role as wholesalers of natural gas, and has substantially increased
competition and volatility in natural gas markets. The FERC has issued final
orders in virtually all Order No. 636 pipeline restructuring proceedings. In
July 1996, the United States Court of Appeals for the District of Columbia
Circuit largely upheld Order No. 636 and remanded certain issues for further
explanation or clarification. Numerous petitions for review of the individual
pipeline restructuring orders are currently pending in that court. The issues
remanded for further action do not appear to materially affect the Company.
Proceedings on the remanded issues are currently ongoing before the FERC
following its issuance of Order No. 636-C in February 1997. Although it is
difficult to predict when all appeals of pipeline restructuring orders will
be completed or their impact on the Company, the Company does not believe
that it will be affected by the restructuring rule and orders any differently
than other natural gas producers and marketers with which it competes.
Although Order No. 636 does not regulate natural gas production
operations, the FERC has stated that Order No. 636 is intended to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service
rates, terms and conditions, it could also subject the Company to more
restrictive pipeline imbalance tolerances and greater penalties for violation
of those tolerances. The Company does not believe, however, that it will be
affected by any action taken with respect to Order No. 636 materially
differently than other natural gas producers and marketers with which it
competes.
The FERC has recently announced its intention to reexamine certain
of its transportation-related policies, including the appropriate manner for
setting rates for new interstate pipeline construction, the manner in which
interstate pipeline shippers may release interstate pipeline capacity under
Order No. 636 for resale in the secondary market, the price that shippers can
charge for their released capacity, and the use of negotiated and
market-based rates and terms and conditions for interstate gas transmission.
Several pipelines have obtained FERC authorization to charge negotiated rates
as an alternative to traditional cost-of-service rate making methodology. In
February 1997, the FERC announced a broad inquiry into issues facing the
natural gas industry to assist the FERC in establishing regulatory goals and
priorities in the post-Order No. 636 environment. In December 1997, the FERC
requested comments on the financial outlook of the natural gas pipeline
industry, including among other matters, whether the FERC's current rate
making policies are suitable in the current industry environment. In April
1998, the FERC issued a new rule to further standardize pipeline transaction
tariffs that, as the result of newly standardized provisions regarding firm
intra day transportation nominations, could adversely affect the reliability
of scheduled interruptible transportation service on some pipelines. While
any resulting FERC action would affect the Company only indirectly, any new
rules and policy statements may have the effect of enhancing competition in
natural gas markets.
Additional proposals and proceedings that might affect the natural
gas industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any
such proposals might become effective, or their effect, if any, on the
operations of the Company. The natural gas industry historically has been
very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by the FERC and Congress will
continue indefinitely into the future. The regulatory burden on the oil and
natural gas industry increases the Company's cost of doing business and,
consequently, affects its profitability and cash flow. In as much as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations.
LOUISIANA LEGISLATION. The Louisiana legislature passed Act 404 in
1993, which permits a party transferring an oil field site to establish a
site-specific trust account for such oil field. If the site-specific trust
account is established in accordance with the requirements of the statute,
the party transferring the oil field site shall
17
<PAGE>
not thereafter be held liable by the state for any site restoration costs or
actions associated with the transferred oil field site. The parties to a
transfer may elect not to establish a site-specific trust account, however,
in the absence of such an account, the transferring party will continue to
have liability for the costs of restoration of the site. If the parties to a
transfer elect to establish a site-specific trust account pursuant to the
statute, the Louisiana Department of Natural Resources ("DNR") requires an
oil field site restoration assessment to be made at the time of the transfer
or within one year thereafter, to determine the site restoration requirements
existing at the time of transfer. Based upon the site restoration assessment,
the parties to the transfer must propose to the DNR a funding schedule for
the site-specific trust account, providing for some contribution to the
account at the time of transfer and at least quarterly payment thereafter. If
the DNR approves the establishment and funding of the site-specific trust
account, the purchaser will thereafter be the responsible party to the state,
except that the failure of a transferring party to make a good faith
disclosure of all oil field site conditions existing at the time of the
transfer will render that party liable for the costs of restoration of such
undisclosed conditions in excess of the balance of the site-specific trust
fund.
OIL SALES AND TRANSPORTATION RATES. The FERC also regulates rates
and service conditions for interstate transportation of crude oil, liquids
and condensate, which can affect the amount the Company receives from the
sale of these products. Rates for such transportation are generally subject
to an indexing system under which rates may be increased as long as they do
not exceed an index rate that is tied to inflation. Over time, this indexing
system could have the effect of increasing the cost of transporting crude
oil, liquids and condensate by pipeline. Sales of crude oil, condensate and
gas liquids by the Company are not regulated and are made at market prices.
The price the Company receives from the sale of these products is affected by
the cost of transporting the products to market.
ENVIRONMENTAL MATTERS. The Company's oil and natural gas
exploration, development and production operations are subject to stringent
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. Numerous governmental agencies, such as the U.S. Environmental
Protection Agency ("EPA"), issue regulations to implement and enforce such
laws, which often require difficult and costly compliance measures that carry
substantial administrative, civil and criminal penalties or may result in
injunctive relief for failure to comply. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentrations of various substances that can be
released into the environment in connection with drilling and production
activities, limit or prohibit construction or drilling activities on certain
lands lying within wilderness, wetlands, ecologically sensitive and other
protected areas, require remedial action to prevent pollution from former
operations, such as plugging abandoned wells, or closing pits, and impose
substantial liabilities for pollution resulting from the Company's
operations. In addition, these laws and regulations may restrict the rate of
oil and natural gas production below the rate that would otherwise exist. The
regulatory burden on the oil and gas industry increases the cost of doing
business and consequently affects its profitability. Changes in environmental
laws and regulations occur frequently, and any changes that result in more
stringent and costly waste handling, storage, transport, disposal or cleanup
requirements could have a material adverse effect on the Company's operations
and financial position, as well as those of the oil and gas industry in
general. While management believes that the Company is in substantial
compliance with current applicable environmental laws and regulations and the
Company has neither experienced any material adverse effect nor experts any
significant capital expenditures from compliance with these environmental
requirements, there is no assurance that this trend will continue in the
future.
The Comprehensive Environmental Response, Compensation and Liability
Act, as amended ("CERCLA"), also known as "Superfund," and comparable state
laws imposes liability without regard to fault or the legality of the
original conduct, on certain classes of persons who are considered to be
responsible for the release of a "hazardous substance" into the environment.
These persons include (i) the current owner and operator of a facility from
which hazardous substances are released, (ii) owners and operators of the
facility at the time the disposal of hazardous substances took place, (iii)
generators of hazardous substances who arranged for the disposal or treatment
at or transportation to such facility of hazardous substances and (iv)
transporters of hazardous substances to disposal or treatment facilities
selected by them. Under CERCLA, such persons may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of hazardous
substances or other pollutants into the environment. Furthermore, although
petroleum, including crude oil and natural gas, is exempt from CERCLA, at
least two courts have ruled that certain wastes associated with the
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<PAGE>
production of crude oil may be classified as "hazardous substances" under
CERCLA, and thus such wastes may become subject to liability and regulation
under CERCLA. Regulatory programs aimed at remediation of environmental
releases could have a similar impact on the Company.
The Resource Conservation and Recovery Act, as amended ("RCRA"),
generally does not regulate most wastes generated by the exploration and
production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes
associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy." However, these wastes may be regulated by
EPA or state agencies as solid waste. Moreover, ordinary industrial wastes,
such as paint wastes, waste solvents, laboratory wastes, and waste compressor
oils, may be regulated as hazardous waste. Pipelines used to transfer oil and
gas may also generate some hazardous wastes. Although the costs of managing
solid and hazardous waste may be significant, the Company does not expect to
experience more burdensome costs than similarly situated companies involved
in oil and gas exploration and production.
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has used
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company or on or under other
locations where such wastes have been taken for disposal. In addition, many
of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the
Company's control. These properties and the wastes disposed thereon may be
subject to CERCLA, RCRA, and analogous state laws. Under such laws, the
Company could be required to remove or remediate previously disposed wastes
(including waste disposal of or released by prior owners or operators), or
property contamination (including groundwater contamination by prior owners
or operators), or to perform remedial plugging or pit closure operations to
prevent future contamination.
The Federal Water Pollution Control Act of 1972 as amended
("FWPCA"), also known as the Clean Water Act ("CWA") and analogous state
laws, impose restrictions and strict controls regarding the discharge of
pollutants including produced waters and other oil and gas wastes, into state
waters or waters of the United States. The discharge of pollutants into
regulated waters is prohibited, except in accord with the terms of a permit
issued by EPA or the state. These proscriptions also prohibit certain
activity in wetlands unless authorized by a permit issued by the U.S. Army
Corps of Engineers. Sanctions for unauthorized discharges include
administrative, civil and criminal penalties, as well as injunctive relief.
The Oil Pollution Act of 1990, as amended ("OPA"), pertains to the
prevention of and response to spills or discharges of hazardous substances or
oil into navigable waters of the United States. Under OPA, a person owning or
operating a facility or equipment (including land drilling equipment) from
which there is a discharge or threat of a discharge of oil into or upon
navigable waters or adjoining shorelines is liable, regardless of fault, as a
"responsible party" for removal costs and damages. Federal law imposes
strict, joint and several liability on facility owners for containment and
clean-up costs and certain other damages, including natural resource damages,
arising from a spill. The OPA establishes a liability limit for onshore
facilities of $350 million; however, a party cannot take advantage of this
liability limit if the spill is caused by gross negligence or willful
misconduct or resulted from a violation of a federal safety, construction, or
operating regulation. If a party fails to report a spill or cooperate in the
cleanup, the liability limits otherwise do not apply. Federal regulations
under the OPA and FWPCA also require certain owners and operators of
facilities that store or otherwise handle oil, such as the Company, to
prepare and implement spill prevention, control and countermeasure plans and
spill response plans relating to possible discharge of oil into surface
waters. The Company believes that it is in substantial compliance with the
requirements of the OPA and FWPCA and that any non-compliance would not have
a material adverse effect on the Company.
COMPETITION
The gas and oil industry is highly competitive in all of its phases.
The Company encounters strong competition from other gas and oil companies in
all areas of its operations, including the acquisition of exploratory and
producing properties, the permitting and conducting of seismic surveys and
the marketing of gas and oil. Many of these competitors possess greater
financial, technical and other resources than the Company. Competition for
the acquisition of producing properties is affected by the amount of funds
available to the Company, information about
19
<PAGE>
producing properties available to the Company and any standards the Company
establishes from time to time for the minimum projected return on investment.
Competition also may be presented by alternative fuel sources, including
heating oil and other fossil fuels. There has been increased competition for
lower risk development opportunities and for available sources of financing.
In addition, the marketing and sale of natural gas and processed gas are
competitive. Because the primary markets for natural gas liquids are
refineries, petrochemical plants and fuel distributors, prices generally are
set by or in competition with the prices for refined products in the
petrochemical, fuel and motor gasoline markets.
FACILITIES
The Company leases approximately 7,600 square feet of office space
in Houston, Texas, at an annual rent of $117,068. The lease expires in
September 2001. The Company leases approximately 13,279 square feet of office
space in Corpus Christi, Texas. The annual rent is $135,446, and the Lease
expires on June 30, 2003. The Company currently has more office space than it
needs in Houston, and has sublet a portion of its office space.
EMPLOYEES
The Company has eight (8) full-time employees in its Houston, Texas
office, and 31 employees in its Corpus Christi, Texas office. Their functions
include management, production, engineering, geology, geophysics, land,
legal, gas marketing, accounting, financial planning and administration.
Certain operations of the Company's field activities are accomplished through
independent contractors who are supervised by the Company. The Company
believes its relations with its employees and contractors are good. No
employees of the Company are represented by a union.
ITEM 2. DESCRIPTION OF PROPERTY
PRINCIPAL AREAS OF OPERATIONS
The Company owns and operates producing properties located in four
states with proved reserves located primarily in Louisiana, Oklahoma and
Texas. Daily production from both operated and non-operated wells net to the
Company's interest averaged 1,794 Mcf per day and 24 Bbls of oil per day for
the year ended December 31, 1998 and 5,526 Mcf per day and 41 Bbls of oil per
day for the quarter ended December 31, 1998. These properties have provided
most of the Company's revenues to date.
DRILLING ACTIVITY
In 1997, the Company participated in eight wells, drilled one
sidetrack operation in an existing wellbore, which operations have resulted
in two successful completions, six dry holes, and one unsuccessful sidetrack
operation due to mechanical difficulties. These results were all prior to the
Acquisitions in May 1998, at which time the exploration functions of the
Company changed dramatically with new projects, new management and a new
focus.
Since November 1, 1997 (the effective date of the Acquisitions)
through December 31, 1998, 24 wells have been drilled for the Company's
account, of which twelve have been completed, eleven were dry holes and one
was drilling. In the first quarter of 1999, the Company participated in the
drilling of six additional wells, of which one had been completed, two are
awaiting completion, one was a dry hole and two were drilling.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the
Company's ownership as of December 31, 1998 of productive gas and oil wells
in the areas indicated.
20
<PAGE>
<TABLE>
<CAPTION>
Gas Oil
---------------- ----------------
Gross Net Gross Net
------ ------- ----- ------
<S> <C> <C> <C> <C>
Texas ................................................ 12 2.73 4 0.75
Oklahoma ............................................. 3 0.01 5 0.08
Louisiana ............................................ 1 0.08 0 0.00
Kansas ............................................... 1 0.10 0 0.00
------ ------- ----- ------
Total ............................................ 17 2.92 9 0.83
------ ------- ----- ------
------ ------- ----- ------
</TABLE>
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the
production volumes, average prices received (net of transportation) and average
production costs associated with the Company's sale of gas and oil for the
periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------
1998 1997
--------------- -----------------
<S> <C> <C>
Net Production:
Oil (Bbl) ........................................................ 8,878 7,286
Gas (Mcf)......................................................... 653,325(1) 121,304
Gas equivalent (Mcfe)............................................. 706,593(1) 165,020
Average sales price:
Oil ($ per Bbl)................................................... $ 10.92 $ 20.28
Gas ($ per Mcf)................................................... $ 1.95 $ 2.06
Average production expenses and taxes ($ per Mcfe)........................ $ 0.52 $ 2.13(2)
</TABLE>
(1) The majority of the net production is attributable to the fourth quarter
of 1998, during which time additional exploration discoveries commenced
production.
(2) This computation includes $164,792 in costs associated with the
fulfillment of contractual transportation obligations on the Company's
Mobile Bay Properties. If this amount were not included, the average
production expenses and taxes per Mcfe would have been $1.13.
LEASEHOLD ACREAGE
The following table sets forth as of December 31, 1998, the gross
and net acres of proved developed and proved undeveloped gas and oil leases
which the Company holds or has the right to acquire. It does not include
unproven acreage, which constitutes the majority of the Company's leasehold
position.
<TABLE>
<CAPTION>
PROVED DEVELOPED PROVED UNDEVELOPED
-------------------- --------------------
STATE GROSS NET GROSS NET
----- -------- ------- -------- ----------
<S> <C> <C> <C> <C>
Arkansas ................................................. 0.0 0.0 6,360.0 2,544.0
Kansas ................................................... 640.0 30.6 0.0 0.0
Louisiana ................................................ 225.0 225.0 9,215.0 3,910.5
Oklahoma ................................................. 2,117.0 50.4 12,908.5 3,727.2
Texas .................................................... 3,016.0 1,390.2 6,980.5 1,339.0
------- ------- -------- --------
Total ............................................ 5,998.0 1,696.2 35,464.0 11,520.7
------- ------- -------- --------
------- ------- -------- --------
</TABLE>
21
<PAGE>
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty,
carried working, net profits, working and other similar interests and
contractual arrangements customary in the gas and oil industry, liens for
current taxes not yet due and other encumbrances. As is customary in the
industry in the case of undeveloped properties, little investigation of
record title is made at the time of acquisition (other than a preliminary
review of local records). Investigations including a title opinion of local
counsel generally are made before commencement of drilling operations. The
Company has granted to an affiliate of a major public utility a mortgage on
its interest in the Starboard Project to secure repayment of the funding
provided by the affiliate and relating to the prospect, and has granted to
Bank of America NT&SA ("B of A") a mortgage on virtually all remaining gas
and oil properties to secure repayment of its credit facility with the bank
and with Duke Energy Field Services, Inc. ("Duke"). B of A serves as
collateral agent for both B of A and Duke pursuant to an intercreditor
agreement between each of them and the Company.
ITEM 3. LEGAL PROCEEDINGS
EPC was a defendant in a lawsuit regarding injuries to a oil field
worker not employed by the Company that resulted in a judgment against EPC of
approximately $17,700,000. The judgment was settled by EPC's insurers, who
agreed to make cash payments to the plaintiff, and by EPC who agreed to
implement a mutually agreeable work safety plan in exchange for approximately
$6.0 million in punitive damages that otherwise would have been payable to
the plaintiff. The settlement was entered into and approved by the court
entering an agreed judgment on December 3, 1997. On approximately April 16,
1998, the plaintiff filed an action against both EPC and the Company
alleging, in part, that EPC has failed and refused to implement an
appropriate safety plan and entered into negotiations with the Company to
convey material assets to it which, if consummated, would negate plaintiffs
benefits to be obtained by EPC's safety plan, thereby fraudulently inducing
plaintiff to settle the judgment against EPC. The Company believes the claims
are not supported by the facts and are without merit. The Company has in fact
implemented a safety plan as part of its business strategy which it believes
equals or exceeds the one EPC agreed to implement. It took this action as
part of its business activities and not due to any obligation it believes
exists to the Plaintiff. The Company and EPC have been advised by counsel for
the plaintiff that the litigation will be dismissed subject to agreement on a
procedure for verification of the Company's ongoing safety plan. Charles J.
Smith and Michael E. Johnson, shareholders of 100% of the common stock of
EPC, have indemnified the Company in the event that any damages were to be
assessed against the Company. In the event it is not timely dismissed, the
Company and EPC will vigorously defend the claims and the Company does not
believe it will sustain any material loss.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On December 3, 1998 the Company held its Annual Meeting of
Shareholders. At said meeting Mr. Hobart Smith and Mr. William D. Dodge III
were re-elected as directors with their new terms expiring at the Annual
Stockholders Meeting in 2001. The vote totals were as follows:
<TABLE>
<CAPTION>
Number of Number of Shares Number of
Shares Voted Shares Voted Shares
For: Against: Abstained
<S> <C> <C> <C>
William D. Dodge III 14,431,500 233 19,046
Hobart A. Smith 14,431,566 167 29,213
</TABLE>
There was no further business submitted to the shareholders for a vote.
22
<PAGE>
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
On November 12, 1993, the Company's predecessor, Frontier Natural
Gas Corporation's common stock, its Convertible Preferred Stock and its
Series A Warrants were all admitted to trading on the NASDAQ Small Cap Market
under the symbols "FNGC" for its common stock, "FNGCP" for its Convertible
Preferred Stock, and "FNGCW" for its Series A Warrants. All of the issued and
outstanding Convertible Preferred Stock was redeemed in June of 1998. The
Series A Warrants expired in November of 1998. On August 9, 1996, Frontier
Natural Gas Corporation's Series B Warrants were admitted to trading on the
NASDAQ Small Cap Market under the symbol "FNGCZ". In May of 1998 the Company
reincorporated in the State of Delaware and changed its name to Esenjay
Exploration, Inc. Its common stock trading symbol changed to "ESNJ" and its
Series B Warrant symbol to "ESNJZ". The Series B Warrants ceased to be listed
on the NASDAQ Small Cap Market in February of 1999 due to insufficient market
makers and are not currently listed on any national market.
The Company's common stock trades on the NASDAQ Small Cap Market
under the symbol "ESNJ". The Company estimates there are approximately 95
common shareholders of record and 2,355 beneficial owners of the common stock.
<TABLE>
<CAPTION>
Convertible Series A Series B
Common Preferred Warrants(1) Warrants
-------------------- ------------------ ----------------- --------------------
Quarter Ended High Low High Low High Low High Low
- ------------- --------- -------- ------- ------ ------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
December 31, 1998 $ 3 3/16 $ 1 1/2 -- -- 5/32 1/32
September 30, 1998 4 3/8 1 13/16 -- -- 7/32 1/32
June 30, 1998 6 3/8 4 10 1/2 10 1/2 3/16 1/16
March 31, 1998 7 1/8 4 1/8 10 7/8 7 1/8 1/4 1/16
December 31, 1997 $12 $ 4 1/8 8 1/2 7 1/8 3/8 1/64 7/16 3/32
September 30, 1997 12 3 3/4 9 7 1/4 3/16 1/16 3/4 1/8
June 30, 1997 14 1/4 10 1/8 10 9 5/16 3/16 15/16 1/2
March 31, 1997 21 3/8 12 3/8 10 5/8 9 1/2 5/32 1 11/16 11/16
</TABLE>
(1) The Series A Warrants expired in November 1998. There were no 1998
trades recorded prior to their expiration.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
The following discussion and analysis reviews Esenjay Exploration,
Inc.'s and/or its predecessor Frontier Natural Gas Corporation's operations
for the twelve month periods ended December 31, 1998 and 1997 and should be
read in conjunction with the consolidated financial statements and notes
related thereto. Certain statements contained herein that set forth
management's intentions, plans, beliefs, expectations or predictions of the
future are forward-looking statements. It is important to note that actual
results could differ materially from those projected in such forward-looking
statements. The risks and uncertainties include but are not limited to
potential unfavorable or uncertain results of 3-D seismic surveys not yet
completed, drilling costs and operational uncertainties, risks associated
with quantities of total reserves and rates of production from existing gas
and oil reserves and pricing assumptions of said reserves, potential delays
in the timing of planned operations, competition and other risks associated
with permitting seismic surveys and with leasing gas and oil properties,
potential cost overruns, potential dry holes and regulatory uncertainties and
the availability of capital to fund planned expenditures as well as general
industry and market conditions.
OVERVIEW
OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH MAY 1998. In
mid-1996, the Company refocused its activities from acquiring gas reserves
principally in the Mid-Continent region of the United States to concentrate on
exploration and related development drilling projects in Southern Louisiana and
along the Gulf Coast
23
<PAGE>
region of Alabama, Mississippi and Texas. During 1996 and 1997, the Company's
drilling activities, which were based primarily on 2-D seismic data, were
largely unsuccessful. This fact, along with an unexpected drop in production
from the Company's Mobile Bay area wells, greatly reduced the Company's cash
and capital resources.
To address the Company's capital needs, the Board of Directors, at
its meeting on August 12, 1997, directed management to look for potential
assets to acquire in exchange for the Company's Common Stock, to identify and
review potential business consolidation opportunities, identify potential
partners to help fund the Company's proposed drilling activities, and to
consider any other avenues to strengthen the Company's capital resources and
diversify its exploration opportunities. The Board also directed management
to reduce overhead wherever prudently possible and the Company retained an
investment advisor to aid in achieving these objectives. The Company explored
a series of such transactions and the Board, after receipt of the advice of
management and its investment advisor, and receipt of due diligence reports
and other materials, unanimously agreed that a transaction with Aspect and
EPC was the best option for the Company's shareholders. This process led to
the Company entering into the Acquisition Agreement among the Company, EPC,
and Aspect. This Acquisition Agreement, and certain provisions of it,
required approval of the shareholders of the Company. At a special meeting of
shareholders held on May 14, 1998 the shareholders approved the Acquisition
Agreement, a recapitalization of the Company pursuant to which each
outstanding share of common stock would convert into one-sixth (1/6) of a
share of new common stock (the "Reverse Split"), a plan and agreement of
merger pursuant to which the Company would reincorporate in the state of
Delaware and would change its name to Esenjay Exploration, Inc. (the
"Reincorporation"), and the election of seven directors.
On May 14, 1998 after a Special Meeting of Shareholders, the Company
closed the transactions provided for in the Acquisition Agreement,
implemented the Reverse Split, and completed the Reincorporation. All
references in the accompanying financial statements to the number of common
shares have been restated to reflect the foregoing. In addition, as required
by the Acquisition Agreement, the Company called for redemption, all of its
issued and outstanding cumulative convertible preferred stock and did redeem
said preferred stock. The result of the foregoing is that the Company
conveyed a substantial majority of its Common Stock to acquire an array of
significant technology enhanced natural gas oriented exploration projects.
The Company believed the Acquisitions would facilitate expanded access to
capital markets due to the value and diversity of its exploration project
portfolio. The Company also believes the members of EPC's management that
joined the Company after consummation of the acquisitions significantly
enhanced the Company's management team.
In connection with the Acquisitions, an affiliate of Enron Corp.
exercised an option to exchange $3.8 million of debt Aspect owed to such
Enron affiliate for 675,000 shares of the Company's Common Stock that would
otherwise have been issued to Aspect in the Acquisitions, at an effective
conversion rate of $5.63 per share. As a result of the Acquisitions and this
exchange and the secondary public offering effective in July of 1998, EPC,
Aspect and the Enron affiliate own approximately 32.8%, 27.7% and 4.3%,
respectively, of the Company's Common Stock.
On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering
the Company had 15,762,723 shares outstanding.
OVERVIEW OF CURRENT ACTIVITIES - SINCE MAY 1998. As a result of the
above-described acquisitions, restructuring, and the underwritten offering,
the Company believes it is positioned for a period of significant exploration
activity on its technology enhanced projects. Many of the projects have
reached the drilling stage. In many instances the requisite process of
geological and/or engineering analysis, followed by acreage acquisition of
leasehold rights and seismic permitting, and 3-D seismic field data
acquisition, then processing of the data and finally its interpretation, took
several years of time and the investment of significant capital. Management
believes the acquisition of projects at this advanced stage has not only
reduced the drilling risk, but should allow the Company to consistently drill
on a broad array of exploration prospects in 1999 and subsequent years. On
Exploration Projects acquired pursuant to the Acquisitions, the Company has
participated in the drilling of twenty-four wells through December 31, 1998
with working interests which range from 8% to 79%. Out of the twenty-four
wells drilled, twelve wells have been completed, eleven were dry holes, and
one is being drilled. Several of the successful wells went into production
late in the third quarter of 1998, and in the fourth quarter of 1998. In
addition, in the first quarter of 1999, the Company participated in six
additional wells of which one was completed, two are awaiting completion, two
were
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drilling, and one was dry. As a result, management believes net daily oil and
gas production, which currently approximates 5,300 Mcfe per day, will
increase to approximately 13,500 Mcfe per day as production from the new
discoveries comes on line.
The Company entered 1999 having gone from nominal second quarter
1998 gas and oil revenues of approximately $35,000 per month and large
operating cash flow deficits to a company with over $360,000 per month in oil
and gas revenues in the fourth quarter of 1998. This number is expected to
exceed $700,000 per month as first quarter 1999 exploration discoveries come
on line and continue to increase as additional wells are drilled. This should
allow it to achieve positive operating cash flow in 1999 and beyond. In
addition, since December 31, 1998, the Company has closed a long term
financing commitment for $9,000,000 with Duke Energy Field Services, Inc., it
has closed a sale of project interests to industry partners for a total of
$3,768,500, and has entered into two agreements to sell additional project
interests for a total of approximately $3,900,000. The closed financing,
combined with the closed project sales, as well as those expected to close,
will result in an aggregate availability of over $16,600,000 in available
cash resources, which is expected to enhance working capital and contribute
to the Company's early 1999 capital expenditure plan. (See "Liquidity and
Capital Resources").
The Company will look to a variety of sources to fund its continuing
capital expenditures budget, including it's new credit facilities and sales
of promoted project interests to industry partners, as it seeks to maximize
its interests and manage its risks while aggressively pursuing its
exploration projects. (see "Liquidity and Capital Resources")
SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company
utilizes the successful efforts method of accounting. Under this method it
expenses its dry hole costs and the field acquisition costs of 3-D seismic
data as incurred. The undeveloped properties which were acquired pursuant to
the Acquisitions, and which were comprised primarily of interests in unproven
3-D seismic based projects, recorded in May of 1998 at an independently
estimated fair market value of $54.2 million as determined by Cornerstone
Ventures, L.P., a Houston, Texas based investment banking firm. Pursuant to
the successful efforts method of accounting, the Company is amortizing such
initial costs as periodic impairments of unproved properties on a
straight-line basis over a period not to exceed forty-eight months, as well
as recognizing property specific impairments. These non-cash charges effect
all such costs which are not, in the accounting period they are to be
impaired, supported by proven oil and gas reserves. Hence significant
non-cash charges will likely depress reported earnings of the Company over
the next several years, but will not effect cash flows provided by operating
activities nor the ultimate realized value of the Company's natural gas and
oil properties.
As a result of the tax rules applicable to the Acquisitions, the
Company will likely not be able to fully use its existing net operating loss
carry forward in the future.
YEAR 2000
The Company is exposed to the risk that the Year 2000 issue could
cause system failures or miscalculations causing disruptions of operations,
including, among other things, a temporary inability to process transactions,
send joint interest billings, or engage in similar normal business
activities. During 1998, the Company undertook a corporate-wide initiative
designed to assess the impact of the Year 2000 issue on software and hardware
utilized in the Company's operations.
The Company's initiative is to be conducted in these phases:
assessment, implementation and testing. During the assessment phase, the
Company completed a comprehensive inventory of all "mission critical" systems
and equipment. Many of the Company's systems include hardware and packaged
software purchased from large vendors who have represented that these systems
are already Year 2000 compliant.
The Company relies on other producers and transmission companies to
conduct its basic operations. Should any third party with which the Company
has a material relationship fail, the impact could impair the Company's
ability to perform its basic operation. Examples of such changes are an
inability to transport production to market or an inability to continue
drilling activities. As part of the Company's assessment phase, the Company
will address the most reasonably likely worst-case scenarios and potential
costs.
The majority of the Company's technical applications are not date
sensitive. Of those applications that are
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date sensitive, most have recently been, or are currently being, upgraded.
The Company intends to complete the testing of Year 2000 modifications during
the third quarter of 1999. The Company has not established a contingency plan
but intends to formulate one to address unavoidable risks, including those
discussed above. The Company expects to have the contingency plan formulated
by the third quarter of 1999.
The Company's efforts with respect to the Year 2000 issue have been
handled internally by management and other Company personnel. Costs of
developing and carrying out this initiative are being funded from the
Company's operations and have not represented a material expense to the
Company. The Company has not completed its assessment but currently believes
that the costs of addressing the Year 2000 issue should not be significant
and should not have a material adverse impact on the Company's financial
condition.
COMPARISON OF 1998 TO 1997.
All comparative discussions should be considered in the context of
the Acquisitions closed on May 14, 1998, which, together with related changes
significantly modified the scope, focus and the method of doing business of
the Company. As a result, the comparisons are of more limited value when
analyzing relevant trends.
REVENUE. Total revenues increased 88.9% from $908,609 for the year
ended December 31, 1997 to $1,716,473 for the year ended December 31, 1998.
Total gas and oil revenues increased 106.6% from $664,126 to
$1,372,002. The increase in gas and oil revenue was attributed mainly to
revenues from wells placed into production during the third and fourth
quarters of 1998. There was a decrease in gain on the sale of assets of
$446,445 from $452,020 reported for 1997 to $5,375 reported for 1998. As a
result of the increase in operations stemming from both exploratory and
developmental drilling, operating fees increased 412.6% from $55,021 for 1997
to $282,020 for 1998. The Company realized a loss from various commodity
transactions totaling $113,911 for 1998 as compared to $375,410 for 1997.
These losses were attributed to various transactions in which the Company
hedged its future gas delivery obligations as a requirement of its bank loan
facility. In addition to the realized losses from commodity transactions, the
Company recorded $128,936 in unrealized gain for 1998 as compared to an
unrealized loss of $128,936 for 1997. This was due to the fact that by year
end 1998 the Company's average production volumes exceeded the hedged
volumes, and it was able to fulfill its hedge commitments. In addition to the
foregoing, the Company had other revenues of $42,051 for 1998 as compared to
$241,788 for 1997.
COSTS AND EXPENSES. Total costs and expenses of the Company
increased 429.4% from $5,862,412 for 1997 compared to $31,037,820 for 1998.
The increases primarily relate to the changes in scope, focus and method of
doing business which occurred upon closing of the Acquisitions. As a result,
staffing and activity volume increased dramatically. Also foundational was
the increase in 3-D seismic and other geological and geophysical work
intended to lead to increased, risk-controlled drilling and ultimately
increased gas and oil reserves and production. Increasing during the year
were amortization of gas and oil properties, exploration costs-geological and
geophysical, exploration costs-dry hole, general and administrative costs,
depletion, depreciation, and amortization, interest expense and production
taxes. Partially offsetting the foregoing increases were decreases in lease
operating expenses, transportation and gathering costs, and delay rentals.
AMORTIZATION OF UNPROVED PROPERTIES FOR IMPAIRMENT was $6,937,300 in
1998 (none in 1997). The Company will amortize the undeveloped and
unevaluated value of the properties acquired pursuant to the Acquisitions
over a period not to exceed forty-eight months. (See "Successful Efforts
Accounting and Related Matters.")
IMPAIRMENT OF GAS AND OIL PROPERTIES increased from $349,384 in 1997
to $5,832,024 in 1998. This non-cash impairment in 1998 is primarily the
result of the expanded property base acquired pursuant to the Acquisitions.
Management's periodic review of each individual Exploration Project resulted
in the decision to expense the book value of certain projects based upon the
belief that they no longer have a realistic potential to realize the book
value from such projects in the future. The impairment charges incurred were
primarily attributable to the Sheriff, Thompson Creek, and Vicksburg Phase II
Exploration Projects. In addition, $1,560,990 of impairment was taken on
producing properties for which the book value exceeded estimated future cash
flow.
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EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL increased 1,110.5%
from $485,956 for 1997 to $5,882,307 for 1998. These exploration costs
reflect the costs of topographical, geological and geophysical studies and
include the expenses of geologists, geophysical crews and other costs of
acquiring and analyzing 3-D seismic data. The Company's exploration
technology enhanced exploration program on the Exploration Projects has
required the acquisition and interpretation of substantial quantities of such
data and these costs have greatly increased for 1998 as compared with 1997.
The Company considers 3-D seismic data a valuable asset; however, its
successful efforts accounting method requires such costs to be expensed for
accounting purposes.
EXPLORATION COSTS - DRY HOLE increased 194.1% from $1,772,746 for
1997 to $5,213,930 for 1998 as a result of increased drilling activity in
1998. During the year, the Company participated in the drilling of
twenty-four wells of which eleven were dry holes that were expensed.
GENERAL AND ADMINISTRATIVE EXPENSES increased 117.4% from $2,070,812
for 1997 as compared to $4,501,656 for 1998. This was primarily attributable
to increases in operational expenses incurred after May 14, 1998, the
effective date of the Acquisition Agreement with Aspect and EPC, and costs
associated with the Acquisitions, after which time the scope of the Company's
activities increased significantly. The primary components of general and
administrative expenses were payroll and payroll taxes, which increased 125%
from $936,304 in 1997 to $2,104,818 in 1998, legal, accounting and other
professional services which increased 37% from $385,384 in 1997 to $528,705
in 1998.
DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 382.1%
from $315,880 for 1997 to $1,522,771 for 1998. The increase to DD&A was
primarily attributable to wells placed in production in the third and fourth
quarters of 1998.
INTEREST EXPENSE increased 917.6% from $60,942 for 1997 to $620,121
for 1998. The increase in interest expense was primarily attributed to a
credit facility with Duke Energy Financial Services, Inc. closed in February
1998 which was paid off in July, 1998 and an increase in borrowings pursuant
to its credit facility with Bank of America NT & SA in October, 1998. The
Company capitalized a large portion of its interest associated with its
on-going projects, of which capitalized amounts totaled $456,901 for 1998 and
$235,977 for 1997.
PRODUCTION TAXES increased 290.8% from $24,497 for 1997 to $95,728
for 1998. The increase in production taxes was attributed to revenues of
wells placed in production during the third and fourth quarters of 1998,
which increase was partially offset by a production tax refund from the State
of Oklahoma for a production enhancement project completed in 1994.
LEASE OPERATING EXPENSE decreased 36.6% from $427,240 for 1997 to
$270,881 for 1998. The reduction in lease operating expense relates back to
ceased operational costs for the Company's Mobile Bay wells in 1997. Lease
operating costs associated with the Mobile Bay wells for 1997 included
$110,000 accrued for plugging and abandonment costs. During 1998, the Company
reversed $68,739 of the accrual associated with these wells. These factors
combined with lease operating expense increases during the third and fourth
quarters of 1998 because of wells placed in production during those periods.
Lease operating costs would have increased from $317,240 in 1997 to $339,620
were the Mobile Bay wells, which are plugged and abandoned, not included. The
increases would be attributable to increased production activities in late
1998.
TRANSPORTATION AND GATHERING COSTS decreased 98.8% from $143,265 for
1997 to $1,719 for 1998. The decrease in transportation and gathering cost
was almost entirely attributable to the ceased production of the Mobile Bay
Wells.
DELAY RENTAL EXPENSE decreased 24.7% from $211,690 for 1997 to
$159,383 for 1998. These rental payments were primarily associated with the
Company's Starboard Prospect and various other prospects. The decrease was
based upon the Company's decision to release certain leases not deemed
significant after seismic evaluation.
NET LOSS PER COMMON SHARE decreased from a net loss of $3.07 per
share for 1997 to a net loss of $2.97 per share for 1998. There was an
increase in net loss applicable to common stockholders of $24,312,527 from
1997 as compared to 1998, but it was more than offset by the increased number
of weighted average common equivalent
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shares at December 31, 1998, resulting from the Acquisitions which closed
May 14, 1998, and the underwritten common stock offering closed July 21,
1998. Approximately 9,882,000 weighted average common equivalent shares were
outstanding at December 31, 1998 as compared to approximately 1,646,000 at
December 31, 1997.
KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE
OPERATING RESULTS.
The Company's future operating results will be substantially
dependent upon the success of the Company's efforts to develop the projects
acquired in the Acquisitions, as well as its other prospects.
While management believes that said projects represent the most
promising prospects in the Company's history, and the wells drilled on
projects acquired pursuant to the Acquisitions in 1998 substantially
increased the Company's revenues, the capital expenditures planned in 1999
will continue to require substantial outlays of capital to explore, develop
and produce. 1998 drilling results have in fact resulted in substantial
revenue increases which were evidenced in the fourth quarter. Wells drilled
in the fourth quarter of 1998 and first quarter of 1999 are expected to
contribute to continued rapid increases in the Company monthly gas and oil
revenues as they come on line in the first and second quarters of 1999.
However, because of the Company's expanded 1999 drilling budget capital from
sources other than cash flow from operations will continue to be required for
funding planned exploration activities.
LIQUIDITY AND CAPITAL RESOURCES
The Company has budgeted approximately $24,000,000 to fund its 1999
capital budget which includes the drilling and/or completion of its interest
in over 40 wells on the Exploration Projects in 1999. The Company's sources
of financing include borrowing capacity under its existing credit facilities
and other potential credit facilities, the sale of promoted interests in the
Exploration Projects to industry partners and cash provided from operations.
The Company entered 1999 having gone from nominal second quarter
1998 gas and oil production of approximately $35,000 per month and large
operating cash flow deficits to a company which averaged over $360,000 per
month in oil and gas revenues in the fourth quarter of 1998, most of which is
attributable to wells which commenced production in September and throughout
the fourth quarter of 1998. This number is expected to continue to increase.
The Company believes it will exceed $700,000 per month as exploratory
discoveries from the first quarter of 1999 come on line. Additional drilling
success in 1999 is expected to continue the trend of rapid increases. This
should allow it to achieve steadily increasing operating cash flow throughout
the year (prior to capital expenditures and new 3-D seismic data acquisition
costs, which costs the successful efforts accounting method utilized by the
Company mandate to be expensed rather than capitalized). In addition, since
December 31, 1998, the Company has closed long term financings for
$9,000,000, closed the sale of project interests for $3,768,500, and has
entered preliminary agreements to sell certain project interests to two
industry partners for a total of approximately $3,900,000. The resultant
aggregate availability of approximately $16,600,000 in cash is expected to
enhance working capital and fund the Company's exploration plan into the
second quarter of 1999.
The two transactions include a sale to Helmerich & Payne, Inc.
("H&P") and a sale to Aspect Resources LLC ("Aspect"), an affiliate. The
Company has entered an agreement to sell to H&P all of its undeveloped
property interests in the Big Hill/Stowell project area and any interests in
a project area called Gill East for $1,300,000. Closing is to occur in
May 1999. It has also entered into an agreement to sell to Aspect a 12.5% (of
100%) interest in the Caney Creek Project, a 12% (of 100%) interest in the
Gillock Project, and all of the Company's undeveloped property interests in
the West Beaumont project area for $2,610,000. Closing is scheduled for
April 1999. Proceeds from the sale will be used to settle amounts due Aspect.
In that Aspect is a related party, closing is subject to receipt of an
independent fairness opinion which management believes will be timely
obtained.
On October 23, 1998, the Company amended and restated its credit
agreement dated January 3, 1996 with B of A. The amended agreement is in a
total amount of $20,000,000 and provided for an immediate borrowing base of
up to $9,000,000. The Company had drawn $7,500,000 pursuant to the B of A
loan facility as of December 31, 1998, and March 26, 1999. The loan is in two
tranches. Tranche A is a revolving facility with no required principal
payments for two years after which it converts into a thirty-six month term
loan. Tranche B is payable in interest only
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until maturity in eighteen months. Both loans are at a varied interest rate
utilizing either the B of A's Alternate Reference Rate (Alternate Reference
Rate is the greater of (i) B of A's Reference Rate and (ii) the Federal Funds
effective rate plus 0.50%) or the London Interbank rate plus 2% for Tranche A
and 4% for Tranche B. The remaining funds will be available for future
drilling activities of the Company, subject to the approval of the bank. The
Tranche A loan is secured by a mortgage on most proven properties currently
owned by the Company. In addition, certain mortgages on the Company's
exploration project inventory secure Tranche B of the credit facility with B
of A as well as the entire credit facility with Duke discussed below. All
such shared collateral is governed by an intercreditor agreement between B of
A and Duke in which B of A serves as the collateral agent. In addition to the
foregoing, B of A received a 2.0% overriding royalty interest,
proportionately reduced to the Company's net interest, in the properties
classified as proven as of the date of closing and received a five year
warrant to purchase 95,000 shares of common stock at a price equal to the
average daily closing price of the Company's common stock for the thirty days
prior to closing of the credit agreement. The credit agreement does not
provide for any additional overriding interests in favor of B of A. Proceeds
of the loan primarily supplement working capital and exploration costs.
On January 28, 1999, the Company closed a credit facility with Duke.
This facility provides for Duke to loan up to $9,000,000 to the Company for
eighteen months. The commitment reduces by $930,000 per quarter for five
quarters and reduces to zero on August 1, 2000. Principal outstanding cannot
exceed the commitment amount at any time. Duke is paid interest at a rate of
prime plus 4%. It also received a right to gather and process, at fair market
value, gas and condensate from a designated area of interest, and a net
revenue interest in certain of the Company's future drilling activities not
to exceed 0.49% of the Company's net interest. Proceeds primarily supplement
exploration costs.
On January 28, 1999, the Company, B of A, and Duke entered into an
intercreditor agreement which governs the collateral which is used to secure
the credit facility with B of A and the credit facility with Duke. Tranche A
of the B of A credit facility is secured by a first mortgage on most of the
Company's proven properties. Collateral securing amounts outstanding under
both the Duke credit facility and Tranche B of the B of A facility is
primarily comprised of mortgages taken on a significant proportion of the
Exploration Projects of the Company which have not been developed. At such
time as drilling is conducted on the Exploration Projects and proven reserves
are discovered, the Company has a right to seek increases in the available
amount to be drawn under Tranche A of its credit facility with B of A. In the
event B of A agrees to increase the amounts available pursuant to Tranche A,
then, subject to Duke's consent, security interests in proven reserves would
be used as additional primary collateral on Tranche A loans from B of A
supporting the borrowing availability increases.
The Company will require additional sources of capital to fund its
exploration budget over the next 12 months. It anticipates substantial growth
of its credit facility with B of A as proven reserves of gas and oil are
added by its exploration program. It also plans to continue to sell promoted
interests in certain of its Exploration Projects to fund its exploration
program over the next 12 months. In the second quarter of 1999, its capital
expenditures budget will be significantly dependent upon sales of additional
interests in the Exploration Projects. Delays in such new sales would delay
the drilling of certain wells.
The Company historically has addressed its long-term liquidity needs
through the issuance of debt and equity securities, through bank credit and
other credit facilities and with cash provided by operating activities. Its
major obligations at March 26, 1999, consisted principally of (i) servicing
loans under the credit facilities with B of A and with Duke and other loans,
(ii) funding of the Company's exploration activities, and (iii) funding of
the day-to-day operating costs.
Many of the factors that may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control,
including, but not limited to, oil and natural gas prices, governmental
actions and taxes, the availability and attractiveness of financing and its
operational results. The Company continues to examine alternative sources of
long-term capital, the acquisition of a company with producing properties for
common stock or other equity securities, including bank borrowings, the
issuance of debt instruments, the sale of common stock or other equity
securities, the issuance of net profits interests, sales of promoted
interests in its Exploration Projects, and various forms of joint venture
financing. In addition, the prices the Company receives for its future oil
and natural gas production and the level of the Company's production will
have a significant impact on future operating cash flows.
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In order to minimize the pricing risk associated with oil and gas
sales, the Company entered into hedging transactions aggregating a
twenty-four month period with Bank of America's Financial Engineering and
Risk Management Group. The hedging instruments called for the delivery of
4,700 MMBtu per day at prices which range from $2.07 to $2.14 per MMBtu for
the period November 1, 1998 through October 31, 2000.
WORKING CAPITAL. At December 31, 1998, the Company had a cash
balance of $646,200 and a working capital deficit of $10,956,500. The working
capital deficit was primarily attributable to substantial exploratory costs,
including the substantial costs of 3-D seismic data acquisition and analysis,
incurred in 1998, and deficit cash flow from operations before changes in
working capital incurred in 1998. It was also effected by the fact that the
Company received approximately $9,000,000 less in net proceeds then planned
from the sale of common stock of the Company in the third quarter. In regard
to said sale, the Company sold fewer shares for less money per share than
planned in its July underwriting primarily due to market conditions beyond
its control. Gas and oil revenues from wells which went into production in
1998 are anticipated to generate revenues which will equal or exceed ongoing
costs of operations (prior to capital expenditures and the cost of new 3-D
seismic data acquisitions) in the first half of 1999 and beyond. Since the
end of 1998, the Company has closed the above-described credit facility with
Duke, closed the sale of project interests to Xplor Energy, Inc. for
approximately $3,768,500 and entered into two previously referenced
agreements to sell additional project interests for approximately $3,900,000,
which, if all closed, will have generated to the Company's account over
$16,600,000 million in available cash resources subsequent to December 31,
1998. Such cash resources serve to substantially improve working capital and
have served to provide significant funds for capital expenditures.
Due to limited working capital as described above, the Company had
slowed its exploration budget in the second half of 1998. Upon the closing of
the credit facilities with B of A, the sale of certain promoted interests and
exploration projects, and receipt of the Duke credit commitment, the Company
increased its exploration activities in the first quarter of 1999. It plans
to continue this more rapid pace of exploratory drilling activities. In order
to fully implement its 1999 exploration budget while maintaining adequate
working capital, the Company will rely upon additional sales of promoted
project interests through the summer of 1999. In this regard, it has budgeted
sales to industry partners netting approximately $10 million in net proceeds
to the Company by the summer of 1999. Delays in projected sales would delay
certain planned drilling. In the second half of the year, it projects certain
increases in its Tranche A facility with B of A. It also expects continued
rapid increases in monthly oil and gas revenues due to its exploration
successes in the first quarter of 1999. Increased revenues are anticipated to
generate significantly increasing cash flow as the year progresses, which
cash flow will also further supplement the Company's working capital.
SUMMARY. The Company believes it is positioned for a period of
significant exploration activity on its technology enhanced projects. Many of
the projects have reached the drilling stage. In many instances the requisite
process of geological and/or engineering analysis, followed by acreage
acquisition of leasehold rights and seismic permitting, and 3-D seismic field
data acquisition, then processing of the data and finally its interpretation
took several years of time and the investment of significant capital.
Management believes the acquisition of projects at this advanced stage has
not only reduced the drilling risk, but should allow the Company to
consistently drill on a broad array of exploration prospects throughout 1999.
As evidence of this activity the Company has participated in the drilling of
twenty-two wells from March through December 31, 1998, with working interests
which range from 8% to 79%. Out of the twenty-two wells drilled, ten wells
were completed, eleven were dry holes and one was being drilled. In the first
quarter of 1999 through March 31, 1999, the Company participated in the
drilling of six wells, of which one was completed, two are awaiting
completion, two were drilling, and one was a dry hole. The Company's recent
drilling results have served to increase its confidence in its anticipated
1999 drilling on the technology enhanced Exploration Projects. The Company
believes its monthly oil and gas revenues will exceed $700,000 per month (at
current natural gas one year futures prices) when the recently drilled wells
are all on line late in the second quarter. In that overhead is stable,
operating cash flow should steadily and substantially increase throughout
1999. Additional exploration success would continue this positive trend.
In that the Company will not fund most of its 1999 capital
expenditure budget from cash flow, the Company will continue to look to a
variety of sources to fund its continuing capital expenditures budget
including credit facilities and sales of promoted project interests to
industry partners, as it seeks to maximize its interests and manage its risks
while aggressively pursuing its exploration projects. This process will be
limited more by capital
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availability than by its inventory of drillable prospects.
Timing of funding its exploration budget will determine the pace of
drilling and, to the extent drilling is successful, the growth of future oil
and gas revenues. Management believes expanded credit facilities will be
available to it in 1999 if it achieves meaningful exploratory and
developmental drilling success, and that strategic sales of prospect
interests will be contracted and closed which will allow it to continue its
planned exploration activities throughout the year.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In 1997, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 128, "Earnings per Share"
and SFAS No. 129, "Disclosure Information about Capital Structure," which
have been reflected in the Company's year-end 1997 and 1998 financial
statements. In 1997, FASB also issued SFAS No. 130, "Reporting Comprehensive
Income", SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information", and SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities". SFAS Nos. 130 and 131 were adopted effective January
1, 1997. The adoption of those standards has had no impact on the Company's
financial statement presentation or disclosures as the Company had no items
of other comprehensive income and operates primarily in one segment. The
Company is still evaluating the impact of the application of SFAS No. 133,
which when adopted, could have a material effect on its financial position,
liquidity or results of operations.
ITEM 6A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS.
Market risk generally represents the risk that losses may occur in
the value of financial instruments as a result of movements in interest
rates, foreign currency exchange rates and commodity prices. The Company has
entered into interest-rate swap agreements to eliminate any movement in
interest rate.
The energy markets have historically been very volatile, and there
can be no assurance that oil and gas prices will not be subject to wide
fluctuations in the future. In an effort to reduce the pricing risks
associated with oil and gas sales, the Company entered into hedging
transactions aggregating a twenty-four month period with B of A's Financial
Engineering and Risk Management Group. The hedging instruments called for the
delivery of 4,700 MMBtu per day at prices which range from $2.07 to $2.14 per
MMBtu for the period November 1, 1998 through October 31, 2000. While the use
of these hedging arrangements limit the downside risk of adverse price
movements, it also limits future gains from favorable movements to the extent
of the hedged volumes.
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ITEM 7. FINANCIAL STATEMENTS
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Esenjay Exploration, Inc.
We have audited the accompanying consolidated balance sheets of Esenjay
Exploration, Inc. (formerly Frontier Natural Gas Corporation) and
subsidiaries (the "Company") as of December 31, 1998 and 1997 and the related
consolidated statements of operations, stockholders' equity and cash flows
for the years then ended. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
from material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the consolidated financial position of the Company as of
December 31, 1998 and 1997, and the results of their operations and their
cash flows for the years then ended in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Houston, Texas
April 14, 1999
32
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1998 1997
--------------- --------------
<S> <C> <C>
Current assets:
Cash and cash equivalents .............................. $ 646,200 $ 690,576
Accounts receivable, net of allowance for doubtful
accounts of $348,984 at December 31, 1998 and
$15,488 at December 31, 1997 ......................... 3,209,633 221,864
Prepaid expenses and other .............................. 122,422 249,328
Receivables from affiliates ............................. 963,700 105,171
--------------- --------------
Total current assets ........................... 4,941,955 1,266,939
Property and equipment ....................................... 70,044,882 4,404,975
Less accumulated depletion, depreciation
and amortization ........................................ (15,517,656) (1,260,605)
--------------- --------------
54,527,226 3,144,370
Other assets ................................................. 447,091 164,699
--------------- --------------
Total assets ................................... $ 59,916,272 $ 4,576,008
--------------- --------------
--------------- --------------
</TABLE>
33
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1998 1997
------------ ------------
<S> <C> <C>
Current liabilities:
Accounts payable .............................................................. $ 8,993,859 $ 911,396
Accounts payable to affiliate, net ............................................ 4,322,548 ---
Revenue distribution payable .................................................. 1,996,091 68,131
Current portion of long-term debt ............................................. 101,236 401,085
Accrued and other liabilities ................................................. 484,756 299,704
------------ ------------
Total current liabilities ............................................ 15,898,490 1,680,316
Long-term debt ..................................................................... 7,500,000 22,680
Non-recourse debt .................................................................. 864,000 864,000
Accrued interest on non-recourse debt .............................................. 331,194 194,274
Other long-term liabilities ........................................................ --- 9,918
------------ ------------
Total liabilities .................................................... 24,593,684 2,771,188
Stockholders' equity:
Cumulative convertible preferred stock $.01 par value; 5,000,000 shares
authorized; 85,961 shares issued and outstanding at December 31, 1997
($859,610 aggregate redemption and liquidation preference) ................. --- 860
Common stock:
Class A common stock, $.01 par value; 40,000,000 shares authorized;
15,784,834 and 1,655,984 outstanding
at December 31, 1998 and 1997, respectively (1) ............................ 157,849 16,560
Unamortized value of warrants issued .......................................... --- (27,163)
Additional paid-in capital (1) ................................................ 77,651,602 14,751,425
Accumulated deficit ........................................................... (42,486,863) (12,936,862)
------------ ------------
Total stockholders' equity ........................................... 35,322,588 1,804,820
------------ ------------
Total liabilities and stockholders' equity ........................... $ 59,916,272 $ 4,576,008
------------ ------------
------------ ------------
</TABLE>
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998,
all numbers of shares and per share amounts have been restated for all
periods presented.
The accompanying notes are an integral part of these financial statements.
34
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1998 1997
------------- ------------
<S> <C> <C>
Revenues:
Gas and oil revenues.................................................... $1,372,002 $ 664,126
Realized loss on commodity transactions................................. (113,911) (375,410)
Unrealized gain (loss) on commodity transactions........................ 128,936 (128,936)
Gain on sale of assets.................................................. 5,375 452,020
Operating fees.......................................................... 282,020 55,021
Other revenues.......................................................... 42,051 241,788
------------- ------------
Total revenues................................................. 1,716,473 908,609
------------- ------------
Costs and expenses:
Lease operating expense................................................. 270,881 427,240
Production taxes........................................................ 95,728 24,497
Transportation and gathering costs...................................... 1,719 143,265
Depletion, depreciation and amortization................................ 1,522,771 315,880
Amortization of unproved properties..................................... 6,937,300 ---
Impairment of oil and gas properties.................................... 5,832,024 349,384
Exploration costs-geological & geophysical.............................. 5,882,307 485,956
Exploration costs-dry hole.............................................. 5,213,930 1,772,746
Interest expense........................................................ 620,121 60,942
Delay rentals........................................................... 159,383 211,690
General and administrative 4,501,656 2,070,812
------------- ------------
Total costs and expenses....................................... 31,037,820 5,862,412
------------- ------------
Loss before provision for income taxes....................................... (29,321,347) (4,953,803)
Benefit (provision) for income taxes......................................... --- ---
Net loss .................................................................... (29,321,347) (4,953,803)
Cumulative preferred stock dividend.......................................... 48,136 103,153
------------- ------------
Net loss applicable to common stockholders................................... $(29,369,483) $(5,056,956)
------------- ------------
------------- ------------
Net loss per common share (1)................................................ $ (2.97) $ (3.07)
------------- ------------
------------- ------------
Weighted average number of common shares outstanding (1)..................... 9,882,227 1,646,311
------------- ------------
------------- ------------
</TABLE>
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998,
all numbers of shares and per share amounts have been restated for all
periods presented.
The accompanying notes are an integral part of these financial statements.
35
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Preferred Class A Unamortized
Stock Common Shares Value of Additional
------------------------------------------- Warrants Paid-in Accumulated
Shares Amount Shares(1) Amount(1) Issued Capital(1) Deficit
------- ------ ---------- --------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance,
December 31, 1996..... 85,961 $ 860 1,644,317 $ 16,443 $(54,325) $14,681,542 $ (7,905,694)
Issuance of common
stock................. -- -- 11,667 117 -- 69,883 --
Cumulative
preferred stock
dividend.............. -- -- -- -- -- -- (77,365)
Amortization of
warrants.............. -- -- -- -- 27,162 -- --
Net loss................ -- -- -- -- -- -- (4,953,803)
------- ----- ---------- -------- -------- ----------- ------------
Balance,
December 31, 1997 .... 85,961 860 1,655,984 16,560 (27,163) 14,751,425 (12,936,862)
Issuance of common
stock for
Acquisitions, net..... -- -- 10,106,700 101,067 -- 49,360,831 --
Redemption of
preferred stock (85,961) (860) -- -- -- (858,750) (228,654)
Amortization of
warrants.............. -- -- -- -- 27,163 -- --
Secondary common
stock offering,
net................... 4,000,000 40,000 14,364,980 --
Issuance of common
stock................. 22,150 222 33,116 --
Net loss................ (29,321,347)
------- ----- ---------- -------- -------- ----------- ------------
Balance,
December 31, 1998..... -- $ -- 15,784,834 $157,849 $ -- $77,651,602 $(42,486,863)
------- ----- ---------- -------- -------- ----------- ------------
------- ----- ---------- -------- -------- ----------- ------------
</TABLE>
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998,
all numbers of shares and per share amounts have been restated for all
periods presented.
The accompanying notes are an integral part of these financial statements.
36
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------
1998 1997
------------ -----------
<S> <C> <C>
Cash flows from operating activities:
Net loss .......................................................... $(29,321,347) $(4,953,803)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization ..................... 1,522,771 315,880
Amortization of unproven property............................. 6,937,300 --
Impairment of oil and gas properties.......................... 5,832,024 349,384
Exploration costs............................................. 11,096,237 2,258,702
Gain on sale of assets........................................ (5,375) (452,020)
Gain on settlement of deferred compensation agreement......... -- (25,794)
Amortization of financing costs and warrants.................. 136,677 46,128
Unrealized (gain) loss on commodity transitions............... (128,936) 128,936
Changes in operating assets and liabilities:
Trade and affiliate receivables............................... (3,846,298) 191,882
Prepaid expenses.............................................. 126,906 198,418
Other assets.................................................. (372,941) 272,679
Trade and affiliate payables.................................. 11,405,011 186,174
Revenue distribution payable.................................. 1,927,960 (292,032)
Accrued and other............................................. 440,990 (118,936)
------------ -----------
Net cash provided by (used in) operating activities........... 5,750,979 (1,894,402)
------------ -----------
Cash flows from investing activities:
Capital expenditures - gas and oil properties...................... (29,818,845) (3,023,253)
Capital expenditures - other property and equipment................ (300,724) (159,679)
Proceeds from sale of assets....................................... 5,191,847 1,002,540
------------ -----------
Net cash used in investing activities........................... (24,927,722) (2,180,392)
------------ -----------
Cash flows from financing activities:
Proceeds from issuance of debt..................................... 15,800,000 182,382
Repayments of long-term debt....................................... (8,641,494) (296,303)
Preferred stock redeemed........................................... (859,610) --
Preferred stock dividends paid..................................... (228,654) (77,365)
Net proceeds from issuance of common stock......................... 14,438,318 --
Cost of issuing stock.............................................. (1,376,193) --
------------ -----------
Net cash provided by (used in) financing activities............. 19,132,367 (191,286)
------------ -----------
Net decrease in cash and cash equivalents.......................... (44,376) (4,266,080)
Cash and cash equivalents at beginning of year.......................... 690,576 4,956,656
------------ -----------
Cash and cash equivalents at end of year................................ $ 646,200 $ 690,576
------------ -----------
------------ -----------
Supplemental disclosure of cash flow information:
Cash paid for interest............................................. $ 835,186 $ 141,356
37
<PAGE>
Supplemental disclosure of non-cash investing and financing activities:
Acquisition of oil and gas properties........................... $54,218,750 --
Assumption of exploration and other costs....................... 2,380,659 --
Assumption of related liabilities............................... 1,000,000 --
Issuance of 10,106,722 shares of common stock................... 50,838,091 --
</TABLE>
The accompanying notes are an integral part of these financial statements.
38
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION - Esenjay Exploration, Inc.'s (the "Company")
primary business activities include gas and oil exploration, production and
sales, primarily along the Texas and Louisiana Gulf Coast areas of the United
States. The accompanying consolidated financial statements include the accounts
of the Company, and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated upon consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
Certain amounts from previous years have been reclassified to conform
to current presentation.
CASH EQUIVALENTS - The Company considers all investments with a
maturity of three months or less when purchased to be cash equivalents.
GAS AND OIL PROPERTIES - The Company uses the successful efforts method
of accounting for gas and oil exploration and development costs. All costs of
acquired wells, productive exploratory wells, and development wells are
capitalized and depleted by the unit of production method based upon estimated
proved developed reserves. Exploratory dry hole costs, geological and
geophysical costs, and lease rentals on non-producing leases are expensed as
incurred. Gas and oil leasehold acquisition costs are capitalized. Costs of
unproved properties are transferred to proved properties when reserves are
proved. Gains or losses on sale of leases and equipment are recorded in income
as incurred and depleted by the unit of production method based upon estimated
proved reserves. Valuation allowances are provided if the net capitalized costs
of gas and oil properties at the field level exceed their realizable values
based on expected future cash flows. This analysis resulted in $1,560,990 of
impairment charges during 1998. Unproved properties are periodically assessed
for impairment and, if necessary, a loss is recognized. Impairments of
$4,271,034 and $349,384 were recognized in 1998 and 1997, respectively.
In addition, the $54,200,000 fair market value assigned to unproven gas
and oil exploration projects contributed by Esenjay Petroleum Corporation
("EPC") and Aspect Resources LLC ("Aspect") pursuant to certain acquisitions of
undeveloped exploration projects (the "Acquisitions") which closed on May 14,
1998 is, until such time as the book value of each such project is either
drilled and transferred to producing properties or is otherwise evaluated as
impaired, are being amortized on a straight-line basis over a period not to
exceed forty-eight months. For the year ended December 31, 1998, such
amortization was $6,937,300.
The costs of multiple producing properties acquired in a single
transaction are allocated to individual producing properties based on estimates
of gas and oil reserves and future cash flows.
OTHER PROPERTY AND EQUIPMENT - Other property and equipment is carried
at cost. The Company provides for depreciation of other property and equipment
using the straight-line method over the estimated useful lives of the assets,
which range from three to ten years.
Upon sale or retirement of an asset, the cost of the asset disposed of
and the related accumulated depreciation are removed from the accounts, and the
resulting gain or loss is reflected in income.
INCOME TAXES - The Company accounts for income taxes on an asset and
liability method which requires, among other things, the recognition of deferred
tax liabilities and assets for the tax effects of temporary differences between
the financial and tax bases of assets and liabilities, operating loss
carryforwards, and tax credit carryforwards.
39
<PAGE>
COMMODITY TRANSACTIONS - The Company attempts to minimize the price
risk of a portion of its future oil and gas production with commodity futures
contracts. Gains and losses on these contracts are recognized in the period in
which revenue from the related gas and oil production is recorded or when the
contracts are closed. To the extent that the quantities hedged under the
commodity transaction exceed current production, the Company recognizes gains or
losses on the overhedged amount.
CAPITALIZED INTEREST - The Company capitalizes interest costs incurred
on exploration projects. Interest capitalized for the years ended December 31,
1998 and 1997 was approximately $456,901 and $235,977, respectively.
GAS BALANCING - The Company records gas revenue based on the
entitlement method. Under this method, recognition of revenue is based on the
Company's pro-rata share of each well's production. During such time as the
Company's sales of gas exceed its pro-rata ownership in a well, a liability is
recorded, and conversely a receivable is recorded for wells in which the
Company's sales of gas are less than its pro-rata share. The Company's gas
balancing position at December 31, 1998 and 1997 was approximately 31,298 MCF
and 29,244 MCF overproduced, respectively.
EXPLORATION COSTS - The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. In 1998
and 1997, the Company expensed $5,882,307 and $485,956 in geological and
geophysical costs respectively and $5,213,930 and $1,772,746 in dry hole costs
respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS - Statement of Financial Accounting
Standards No. 107. "Disclosures about Fair Value of Financial Instruments"
requires disclosure regarding the fair value of financial instruments for which
it is practical to estimate that value. The carrying amount of cash and cash
equivalents, accounts receivable and accounts payable, approximates fair market
value because of the short maturity of those instruments. The fair value of the
Company's long-term debt is estimated to approximate carrying value based on the
borrowing rates currently available to the Company for bank loans with similar
terms and average maturities.
The Company has interest rate and gas swap agreements that subject it
to off-balance sheet risk. The unrealized losses on these contracts, as
disclosed in the following footnotes, are based on market quotes. These
unrealized losses are not recorded in the consolidated financial statements to
the extent the swaps qualify for hedge accounting.
EARNINGS PER SHARE - Basic earnings per share has been computed by
dividing net income to common shareholders by the weighted average number of
common shares outstanding. Diluted earnings per share is calculated by dividing
net income to common shareholders by the weighted average number of common
shares outstanding plus dilutive potential common shares. For the years ended
December 31, 1998 and 1997 all potentially diluted securities are anti-dilutive
and therefore are not included in the earnings per share calculation.
The following table presents information necessary to calculate basic
and diluted earnings per share for the periods indicated:
<TABLE>
<CAPTION>
1998 1997
------------ -----------
<S> <C> <C>
BASIC AND DILUTED EARNINGS PER SHARE
Weighted average common shares outstanding ............... 9,882,227 1,646,311
Basic and diluted loss per share.......................... $ (2.97) $ (3.07)
------------ -----------
EARNINGS FOR BASIC AND DILUTED COMPUTATION
Net loss.................................................. $(29,321,347) $(4,953,803)
Preferred share dividends................................. (48,136) (103,153)
------------ -----------
Net loss to common shareholders (basic and diluted
loss per share computation)............................. $(29,369,483) $(5,056,956)
------------ -----------
------------ -----------
</TABLE>
40
<PAGE>
2. RECENT EVENTS
On January 28, 1999, the Company closed a credit facility with Duke
Energy Financial Services, Inc. ("Duke"). This facility provides for Duke to
loan up to $9,000,000 to the Company for eighteen months. The commitment reduces
by $930,000 per quarter for five quarters and reduces to zero on August 1, 2000.
Principal outstanding cannot exceed the commitment amount at any time. Duke is
paid interest at a rate of prime plus 4%. Duke also received a right to gather
and process, at fair market value, gas and condensate from a designated area of
interest, and a net revenue interest in certain of the Company's future drilling
activities not to exceed 0.49% of the Company's net interest. Proceeds from the
credit facility will primarily supplement exploration costs.
On January 28, 1999, the Company, Bank of America NT&SA ("B of A"), and
Duke entered into an intercreditor agreement which governs the collateral which
is used to secure the credit facility with B of A and the credit facility with
Duke. Tranche A of the B of A credit facility is secured by a first mortgage on
most of the Company's proven properties at a given point in time. Collateral
securing amounts outstanding under both the Duke credit facility and Tranche B
of the B of A facility is primarily comprised of mortgages taken on a
significant proportion of the exploration projects of the Company which have not
been developed. At such time as drilling is conducted on the exploration
projects and proven reserves are discovered, the Company has a right to seek
increases in the available amount to be drawn under Tranche A of its credit
facility with B of A. In the event B of A agrees to increase the amounts
available pursuant to Tranche A, then, subject to Duke's consent, security
interests in proven reserves would be used as additional primary collateral on
Tranche A loans from B of A supporting the borrowing availability increases.
In January 13, 1999, the Company closed the sale of approximately
23.45% of its interest in its Willacy County Project to a third party for
$3,768,500 plus potential future additional payments based upon future drilling
activity.
On March 22, 1999, the Company entered into an agreement with Aspect to
sell a 12.5% (of 100%) interest in the Caney Creek Project, a 12% (of 100%)
interest in the Gillock Project, and all of the Company's undeveloped property
interests in the West Beaumont project area for $2,610,000. Closing is scheduled
for April 1999. In that Aspect is a related party, closing is subject to receipt
of an independent fairness opinion which management believes will be timely
obtained. Proceeds will be utilized to reduce net accounts payable of $4,322,548
at December 31, 1998 from the Company to Aspect. In addition, on March 31, 1999
the Company entered into an agreement with Helmerich & Payne, Inc. to sell all
of its undeveloped property interests in the Big Hill/Stowell project area and
an area called East Gill for $1,300,000. Closing is expected in April 1999.
3. STOCKHOLDERS' EQUITY:
As a result of the Company's 1:6 reverse stock split effected May 14,
1998, all numbers of common shares and per share amounts have been restated for
all periods.
At December 31, 1996, the Company had 1,644,317 outstanding shares of
$0.01 par value common stock and 85,961 shares of cumulative convertible
preferred stock. In 1998 and 1997 the Company issued 14,128,850 and 11,667
additional shares of common stock, respectively.
On May 14, 1998, the shareholders approved the January 19, 1998
Acquisition Agreement with EPC and Aspect. This agreement called for the Company
to issue up to 5,165,260 shares of Common Stock, after giving effect to the
reverse split, to EPC in exchange for undeveloped oil and gas prospects and to
issue up to 4,941,440 shares of Common Stock, after giving effect to the reverse
split, to Aspect in exchange for undeveloped oil and gas prospects. The combined
assets of Aspect and EPC had a historical full cost basis of $19,900,000 and a
fair value of $54,200,000 as determined by an independent assessment by
Cornerstone Ventures L.P.. In addition, after November 1, 1997 (the effective
date) and prior to the date of closing, EPC incurred approximately $3,800,000 in
exploration and development costs and $300,000 in overhead costs associated with
the prospects and Aspect incurred approximately $3,955,000 in such costs, all of
which incurred costs were for the account of the Company.
CUMULATIVE CONVERTIBLE PREFERRED STOCK - During 1998 and 1997, $48,136
and $77,365 was declared and paid in cumulative preferred stock dividends. In
addition, during 1998 the Company paid dividends in arrears of
41
<PAGE>
$180,518 ($1.50 per share) on its cumulative preferred stock for the period
from May 1, 1995 to December 31, 1998. All shares of the cumulative
convertible preferred stock were redeemed in May of 1998.
WARRANTS - As of December 31, 1996, there were 263,013 Series A
Warrants outstanding. All of the Series A Warrants expired on November 13, 1998.
Since December 31, 1996, the Company has had Series B Warrants, which
entitles the holder to purchase one-sixth (1/6) share of common stock for $12.15
commencing August 8, 1997, and ending August 8, 2001. Each Series B Warrant is
redeemable by the Company with the prior consent of the underwriter at a price
of $0.06 per Series B Warrant, at any time after the Series B Warrants become
exercisable, upon not less than 30 days notice, if the last sale price of the
common stock has been at least 200% of the then exercise price of the Series B
Warrants for the 20 consecutive trading days ending on the third day prior to
the date on which the notice of redemption is given.
The Company had also issued a common stock warrant to purchase 4,167
shares of common stock at $24.00 per share in connection with a loan agreement.
This warrant expired on November 13, 1998. The loan was paid in full in 1993.
The Company and Hi-Chicago Trust agreed to a settlement in December
1995 whereby the Company issued 12,500 shares of common stock and a stock
purchase warrant to purchase up to 50,000 shares of common stock at an exercise
price of $18.00 per share to settle a claim asserted by Hi-Chicago Trust. The
warrant is exercisable through the earlier of 60 months from the settlement date
or for a period of 30 days after the closing bid price of the Company's stock
equals or exceeds $36.00 per share for sixty consecutive trading days. The
issued shares are unregistered.
In 1996, the Company issued to a bank providing financing, a warrant to
purchase up to 41,667 shares of common stock for a period of five years
beginning January 3, 1996, at an exercise price of the highest average of the
daily closing bid prices for thirty (30) consecutive trading days between
January 1, 1996, and June 30, 1996. The Company has recorded the warrants at a
value of approximately $82,500 as unamortized value of warrants issued. The
warrants were amortized using the interest method and were fully amortized
during 1998.
The Company has also issued a warrant to purchase 41,667 shares of the
Company's common stock at $12.00 per share to a financial advisor. The warrant
has a five year term commencing on January 12, 1996 and provides for anti-
dilution protection, registration rights, and permits partial exercise at the
election of the holder by exchanging the warrants with appreciated value equal
to each exercise price in lieu of cash. The Company has recorded the warrants at
their fair value of approximately $33,000.
On January 15, 1997, the Board of Directors authorized the Company to
enter into an agreement with a company to perform investor relations services
for the Company on a fee basis through January 15, 1999, and month to month
thereafter, which fee may be paid either in cash or common stock at the election
of the Company. The Company elected to compensate the investor relations firm
partially in cash and partially in stock, therefore the investor relations firm
was issued 11,667 shares of common stock during 1997 and 12,500 shares in 1998.
In the first quarter of 1998, the Company, in connection with a
financing arrangement, issued warrants to purchase 25,000 shares of common stock
at an exercise price of $3.00 per share.
On October 13, 1998, the Company entered into an amended credit
agreement with B of A part of which called for the Company to issue warrants to
purchase 95,000 shares of common stock at a price per share equal to the average
daily closing price of the Company's common stock during the 30 calendar days
prior to closing. The warrants have a five year term and provide for usual and
customary anti-dilution protection, registration rights, and put and call
provisions (including a call on the warrants if the stock price exceeds five
times the strike price).
EMPLOYEE OPTION PLAN-1997 - The plan authorizes the issuance of up to
115,892 options to purchase one share of common stock. Options to purchase
94,001 shares of common stock at prices ranging from $3.78 to $7.68 are
currently outstanding.
42
<PAGE>
Under the plan, the Board may grant options to officers and other
employees. Each option shall consist of an option to purchase one share of
common stock at an exercise price that shall be at least the fair market value
of the Common stock on the date of the grant of the option. However, the Board
may authorize vesting options as it deems necessary; such is the case of certain
officers reissued options under this plan during 1997. Unless otherwise so
designated, the options shall be exercisable at a rate of 33 1/3% on January 1,
the year following the effective date of the grant, and 33 1/3% each January 1
thereafter. The Option holder's right is cumulative. Unless otherwise designated
by the Board, if the employment of the Option holder is terminated for any
reason, all unexercised Options shall terminate, be forfeited and shall lapse
within three months thereafter.
The options have a maximum life of ten years from the date of issuance.
MANAGEMENT INCENTIVE STOCK PLAN - The Plan initially authorized the
issuance of up to 40,000 units. Each unit consisted of (i) an option to purchase
one share of Common Stock and (ii) a cash payment ("Stock Appreciation Right" or
"SAR") to be made by the Company when the option is exercised. The value of the
SAR was equal to twice the amount by which the fair market value of the Common
Stock on the date of the exercise of the option exceeds the exercise price.
Currently all units have expired or have been canceled by the Board of Directors
and the plan is not effective.
The following table summarizes activity under the Company's stock
option plans for the years ended December 31, 1998 and 1997.
<TABLE>
<CAPTION>
INCENTIVE MANAGEMENT STOCK INCENTIVE EMPLOYEE OPTION
STOCK OPTION PLAN INCENTIVE STOCK PLAN OPTION PLAN 1997 PLAN 1997
----------------- -------------------- ---------------- -----------------
1998 1997 1998 1997 1998 1997 1998 1997
---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Shares available for grant.. --- --- --- --- --- 1,333 115,892 115,892
Shares under option at end
of period................ --- --- --- 8,000 --- 20,333 94,001 100,167
Option price per share...... --- --- --- $12.00-21.00 --- $8.82-12.75 $3.78-7.68 $3.78-11.28
Shares exercisable at end
of period................ --- --- --- 8,000 --- 6,778 90,667 90,667
Sales canceled.............. --- 30,000 --- 10,667 --- 36,667 --- ---
Weighted option price....... --- --- --- $18.12 --- $10.02 $3.92 $4.20
Weighted average fair value
of options granted during
the year at market price --- $3.30
</TABLE>
STOCK OPTION PLANS - The Company has one active fixed option plan which
reserves shares of common stock for issuance to executives, key employees and
directors. The Company has adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation". Accordingly, no compensation cost has been recognized for the
stock option plans. Had compensation cost for the Company's stock option plans
been determined based on fair value at the grant date for awards in 1998 and
1997 consistent with the provisions of SFAS No. 123, the Company's pro forma net
loss applicable to common stockholders and net loss per common and common
equivalent share would have been as indicated below:
<TABLE>
<CAPTION>
1998 1997
------------ -----------
<S> <C> <C>
Net loss applicable to common stockholders-as reported........... $(29,369,483) $(5,056,956)
Net loss applicable to common stockholders-pro forma............. $(29,370,094) $(5,679,620)
Net loss per common share-as reported............................ $(2.97) $(3.07)
Net loss per common share-pro forma.............................. $(2.97) $(3.42)
</TABLE>
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following weighted-average
assumptions: no dividends; expected volatility of 60%; risk-free interest rate
of 5.71% in 1998 and 1997; and expected lives of five (5) years.
43
<PAGE>
OPTION REPRICINGS - In the last quarter of 1997, the Company
determined to attempt to consummate a significant corporate transaction in
order to satisfy the Company's need for additional capital resources. In
connection with pursuing such a transaction, Mr. Berry and Mr. Christofferson
entered into Incentive Agreements and Contract Settlement Agreements with the
Company pursuant to which each of Mr. Berry and Mr. Christofferson were
entitled to receive certain Incentive Payments and Contract Settlement
Payments upon the consummation of such a transaction. The Acquisitions were
such a transaction. Their employment agreements terminated upon the
consummation of the Acquisitions.
In negotiating the terms of the Incentive Agreements and Contract
Settlement Agreements, Mr. Berry and Mr. Christofferson determined that their
existing stock options would expire 90 days after their termination of
employment. The Compensation Committee of the Board of Directors which was
comprised of Messrs. Sweeny and Elliott, each of whom was an outside
director, recognized that the expiration of those options would result in a
disincentive for Mr. Berry and Mr. Christofferson to help the Company pursue
a significant corporate transaction. Therefore, the Compensation Committee
determined that Mr. Berry's and Mr. Christofferson's existing stock options
should be canceled and replaced with new stock options that would terminate
not sooner than the date their old options would have expired if their
employment with the Company was not terminated. As an added incentive, the
Compensation Committee determined to reprice Mr. Berry's and Mr.
Christofferson's options so they could more readily benefit from any upturn
in the Company's Common Stock trading price upon the consummation of a
significant corporate transaction.
When determining the price at which Mr. Berry's and Mr.
Christofferson's new options would be exercisable, the Compensation Committee
took the average closing price of the Company's Common Stock on the NASDAQ
Small-Cap Market over the 20 day trading period immediately preceding the
option reprice date, and multiplied such average trading price by 65%. The
Compensation Committee believed that the discount to the average trading
price was appropriate because the shares of Common Stock issuable upon
exercise of the repriced options would not be freely tradable and the
discount was appropriate to reflect the actual fair market value of the
liquid shares that would be received upon the exercise of the new options.
The following table sets forth certain information with respect to
replacement stock options granted to Mr. Berry and Mr. Christofferson during
the year ended December 31, 1997, which are also reported above under "Option
Grants." There were no replacement stock options issued in 1998.
<TABLE>
<CAPTION>
LENGTH OF
NUMBER OF ORIGINAL OPTION
SECURITIES OF TERM REMAINING
UNDERLYING MARKET PRICE OF EXERCISE PRICE AT DATE OF
OPTIONS/SARS STOCK AT TIME OF AT TIME OF NEW REPRICING OR
REPRICED OR REPRICING OR REPRICING OR EXERCISE AMENDMENT
NAME DATE AMENDED AMENDMENT AMENDMENT PRICE (MONTHS)
---- ------- ------------- ---------------- -------------- -------- ----------------
<S> <C> <C> <C> <C> <C> <C>
David W. Berry............ 12/3/97 20,000 $5.82 $ 9.72 $3.78 102
President and 12/3/97 4,000 $5.82 $18.60 $3.78 69
Chief Executive Officer
David B. Christofferson... 12/3/97 30,000 $5.82 $10.08 $3.78 62
Executive Vice 12/3/97 4,000 $5.82 $18.60 $3.78 69
President, General 12/3/97 16,667 $5.82 $ 8.82 $3.78 102
Counsel and Secretary
</TABLE>
4. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA:
The Company sold various properties in a number of different
transactions during 1998 and 1997. These sales resulted in an aggregate gain
of approximately $485,813 for 1997. No gain or loss was recorded on the sale
of gas and oil assets in 1998 as these were the sale of partial interests in
several unproved properties and the proceeds were treated as a recovery of
costs.
44
<PAGE>
5. LONG-TERM DEBT:
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1998 1997
---------- ------------
<S> <C> <C>
Note payable repaid in 1998....................................................... $ $274,922
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest
accrued at 15%................................................................. 864,000 864,000
Note payable to bank, interest at 7.49% to 12.5%, payable in monthly
installments, collateralized by other property and equipment................... 1,236 48,843
Note payable, interest at 12%, payable monthly, is currently due.................. 100,000 100,000
Loan with B of A, in two Tranches: Tranche A is a revolving credit facility
which terminates October 13, 2000, thereafter converting the unpaid balance
into a five year term loan requiring quarterly principle and interest
payments; Tranche B is payable in interest only until maturity on April 13,
2000, at which time payment in full is required. Both loans are at a varied
interest rate utilizing either the B of A's Alternative Reference Rate
(Alternative Reference Rate is the greater of (i) B of A's Reference Rate
and (ii) the Federal Funds effective rate plus 0.50%) or the Interbank rate
plus 2% for Tranche A and 4% for Tranche B. The loan is secured by a
mortgage on all properties currently owned by the Company 7,500,000 --
---------- ------------
8,465,236 1,287,765
Less current portion.............................................................. 101,236 401,085
---------- ------------
$8,364,000 $886,680
---------- ------------
---------- ------------
</TABLE>
Maturities of long-term debt (excluding non-recourse debt, which is
solely dependent upon the successful development and future production, if
any, of the Starboard Prospect) are as follows:
<TABLE>
<CAPTION>
YEAR AT DECEMBER 31,
---------------
1998
---------------
<S> <C>
1999.................................................................... $ 101,236
2000.................................................................... 4,412,500
2001.................................................................... 650,000
2002.................................................................... 650,000
2003.................................................................... 650,000
</TABLE>
The remaining balance of $1,137,500 will be paid in 2004 and 2005.
45
<PAGE>
On October 13, 1998, the Company amended and restated the credit
agreement dated January 3, 1996 with B of A to an amount equal to the lesser
of the Collateral Value, or $20,000,000. The amended agreement provided for
an immediate borrowing base of up to $9,000,000 ($8,250,000 if the Company
did a third party financing in which the third party lender would share in
certain collateral of B of A). The $9,000,000 base represents the Collateral
Value until the initial Collateral Value Redetermination is made. The Company
has drawn $7,500,000 pursuant to the B of A facility. The loan is in two
tranches. Tranche A is a revolving facility which terminates on October 13,
2000 thereafter converting the unpaid balance into a five year term loan
requiring quarterly principle and interest payments. Tranche B is payable in
interest only until maturity on April, 13, 2000 at which time payment in full
is required. In conjunction with this financing, B of A received a 2%
overriding royalty interest, proportionately reduced to the Company's net
interest, in the properties classified proven as of the date of closing and
received a five year warrant to purchase 95,000 shares of common stock at a
price equal to the average daily closing price of the Company's common stock
for the thirty days prior to closing of the credit agreement. Proceeds of the
loan primarily supplement working capital. As part of the credit agreement,
the Company is subject to certain covenants and restrictions, among which are
the limitations on additional borrowing, and sales of significant properties,
working capital, cash, and net worth maintenance requirements and a minimum
debt to net worth ratio. The covenants regarding financial condition of
Company are as follows:
<TABLE>
<S> <C>
Tangible Net Worth............................ $45,000,000 + 50% of Consolidated Net Income + 100% of net
proceeds received from sale of any Non-Redeemable Stock
Current Ratio................................. 1.1:1.0
Debt to Capitalization........................ 0.5:1.0
Interest Coverage Ratio ...................... 1.0:1.0 - 4th quarter 1998 and 1st quarter 1999, 3.0:1.0 2nd qtr
1999 and any consecutive quarters after June 30, 1999
</TABLE>
At December 31, 1998 the Company's tangible net worth as calculated
pursuant to the Credit Agreement was $35,322,586. B of A has waived
noncompliance with this covenant at December 31, 1998 and March 31, 1999. The
Company and B of A have been in discussions, both recognizing that the
covenant as initially established did not give adequate consideration to the
effects of the Company's successful efforts method of accounting on the
future book value of its properties, in particular the accounting treatment
that the Company has adopted which requires the amortization over a period
not to exceed forty-eight months of a substantial portion of the property
values recorded pursuant to the Acquisitions. As such, B of A has agreed with
the Company in concept to reduce the tangible net worth requirement to an
amount not in excess of $25,000,000, subject to approval of B of A's credit
committee anticipated in the second quarter of 1999. In the event the credit
committee does not approve the modification of the covenant, the Company
would be in noncompliance of this provision and will seek alternative
financing arrangements.
Further, as of December 31, 1998, the Company's current ratio was
0.3128:1 and the Company's interest coverage ratio was (2.1368) to 1, both of
which were, therefore, in noncompliance. B of A has waived said noncompliance
at December 31, 1998. The Company believes it has improved its current ratio
and its interest coverage ratio since December 31, 1998 significantly;
however, it does not believe it is likely that it will be in compliance with
either of said covenants as of March 31, 1999. B of A has indicated that, in
the event the Company is in noncompliance, it will likely waive any such
covenants through April 1, 1999. Although the Company believes it can be in
compliance with both of these covenants throughout the remainder of 1999,
there can be no assurance that it will be in compliance. As a result it is
possible that additional waivers may be needed in the future. In the event B
of A did not grant such waivers, if needed, the Company would be in
noncompliance of the covenants and would seek alternative financing
arrangements.
In addition, the Company has entered into an interest rate swap
guaranteeing a fixed interest rate of 8.28% on the loan, and the Company will
pay fees of one-eighth of 1% (.0125%) on the unused portion of the commitment
amount. The unrealized loss on the interest rate swap agreement was $21,910
and $1,275 at December 31, 1997 and 1998, respectively.
46
<PAGE>
On March 12, 1996, the Company completed a financial package with a
group funded by a public utility to evaluate and develop a project in
Terrebonne Parish, Louisiana. This group will participate in 48% of all costs
of evaluation and development of the project area and provided a non-recourse
loan to fund the Company's 48% share of the leasehold and seismic evaluation
costs of the project. The loan is secured by a mortgage on the Company's
interest in the project. As of December 31, 1998 and 1997, the Company has
received advances aggregating $864,000 on the non-recourse loan. The
non-recourse loan will be paid solely by the assignment on an 8% overriding
royalty interest in the future revenues of the financed project. Future
funding will be provided as costs are incurred.
6. INCOME TAXES:
Deferred tax assets and liabilities are as follows:
<TABLE>
AT DECEMBER 31,
---------------------------------
1998 1997
--------------- --------------
<S> <S> <S>
Net operating tax loss carryforward.................................. $ 11,633,159 $ 4,332,710
Property and equipment............................................... (435,246) (2,936,284)
Valuation allowance.................................................. (11,197,913) (1,396,426)
--------------- --------------
Net deferred tax asset (liability)................................ $ --- $ ---
--------------- --------------
</TABLE>
The Company has recorded a deferred tax valuation allowance since,
based on an assessment of all available historical evidence, it is more
likely than not that future taxable income will not be sufficient to realize
the tax benefit. The Company and its subsidiaries have net operating loss
carryforwards ("NOLs") at December 31, 1998, of approximately $33,200,000
which may be used to offset future taxable income. The operating loss
carryforwards expire in the tax years 2006 through 2013.
The ability of the Company to utilize NOLs and tax credit
carryforwards to reduce future federal income taxes of the Company may be
subject to various limitations under the Internal Revenue Code of 1986, as
amended (the "Code"). One such limitation is contained in Section 382 of the
Code which imposes an annual limitation on the amount of a corporation's
taxable income that can be offset by those carryforwards in the event of a
substantial change in ownership as defined in Section 382 ("Ownership
Change"). In general, Ownership Change occurs if during a specified
three-year period there are capital stock transactions, which result in an
aggregate change of more than 50% in the beneficial ownership of the stock of
the Company. In connection with the Acquisition Agreement, the Company has
incurred such an Ownership Change.
7. RELATED PARTY TRANSACTIONS:
The Company's outstanding advances to employees and affiliates of
the Company at December 31, 1998 and 1997 was $963,700 and $105,171,
respectively. The December 31, 1998 and 1997 receivables include
approximately $47,787 from an affiliated partnership for which the Company
serves as the managing general partner. In addition, the December 31, 1998
balance includes a $915,342 receivable from Esenjay Petroleum (EPC) primarily
related to joint interest billings to EPC. In addition, amounts payable of
$134,400 and $112,000 were due to David W. Berry and David B Christofferson,
respectively, in conjunction with the settlement of their prior employment
contracts. In addition, at December 31, 1998 the Company had a net account
payable to Aspect in the amount of $4,322,548. (See Note 9)
8. COMMITMENTS AND CONTINGENCIES:
The Company leases office space under lease agreements, which are
classified as operating leases. Lease expense under these agreements was
$193,515 in 1998 and $112,432 in 1997. A summary of future minimum rentals on
these non-cancelable operating leases is as follows:
47
<PAGE>
<TABLE>
<CAPTION>
AT DECEMBER 31,
YEAR 1998
- ---- ---------------
<S> <C>
1999.................................................................... $252,514
2000.................................................................... $252,514
2001.................................................................... $213,491
2002.................................................................... $135,446
2003.................................................................... $67,723
</TABLE>
The Company is party to various lawsuits arising in the normal
course of business. Management believes the ultimate outcome of these matters
will not have a material effect on the Company's consolidated financial
position, results of operation, and net cash flows.
The Company markets its natural gas through monthly spot sales.
Because sales made under spot sales contracts result in fluctuating revenues
to the Company depending upon the market price of gas, the Company may enter
into various hedging agreements to minimize the fluctuations and the effect
of price declines or swings. During January 1999, the Company completed
performance on a 1996 swap agreement on approximately 1,040 MMBtu's per day
of Mid-Continent natural gas production for $1.566 per MMBtu for the period
beginning April 1, 1996 and ending January 31, 1999.
In October of 1998, the Company entered into two swap agreements,
one on 4,000 MMBtu's per day of its Gulf Coast natural gas production for
$2.14 per MMBtu for the period beginning November 1998 and ending in October
1999, and the second one on 700 MMBtu's per day of its Gulf Coast natural gas
production for $2.13 per MMBtu for the period beginning November 1998 and
ending in October 1999. Both of these swap agreements were supplemented in
December 1998 when the Company entered into additional swap agreements, one
of which was for 4,000 MMBtu's per day of its Gulf Coast natural gas
production for $2.07 per MMBtu for the period beginning November 1999 and
ending in October 2000, and the second one was on 700 MMBtu's per day of its
Gulf Coast natural gas production for $2.07 per MMBtu for the period
beginning November 1999 and ending in October 2000. As a result of the
foregoing transactions, the Company has 4,700 MMBtu's per day of its Gulf
Coast natural gas production hedged through October 2000.
9. ACQUISITIONS:
On May 14, 1998, the Company acquired substantial interests in 28
exploration projects from EPC and Aspect in exchange for 10,106,700 shares of
the Company's common stock. The estimated fair value on the date of
acquisition was approximately $60 million, which consists of the fair market
value of $54.2 million, as determined by an independent third party, plus
project costs from the effective date of November 1, 1997 up to the closing
of the Acquisition Agreement. The acquired projects are primarily technology
enhanced natural gas exploration projects along the Texas and Louisiana Gulf
Coast.
The Acquisitions have been recorded at their fair value and have been
included in the Company's consolidated financial statements from the date of
their acquisition. The following unaudited pro forma information presents a
summary of condensed consolidated results of operations as if the
Acquisitions had occurred on January 1, 1997:
48
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997
------------ ------------
<S> <C> <C>
Revenues ................................ $ 1,716,473 $ 908,609
Total costs and expenses ................ (33,325,677) (12,865,085)
------------ ------------
Net loss ................................ $(31,609,204) $(11,956,476)
------------ ------------
------------ ------------
Basic and diluted loss per share ........ $ (2.33) $ (1.02)
------------ ------------
------------ ------------
</TABLE>
10. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1998
------------ -----------
<S> <C> <C>
Gas and oil properties, at cost, successful
efforts method of accounting:
Proved ..................................... $ 14,006,224 $ 1,181,811
Unproved, subject to amortization .......... 43,800,198 --
Unproved, not subject to amortization ...... 10,835,056 2,054,037
------------ -----------
Total gas and oil properties ............ 68,641,498 3,235,848
1,403,384 1,169,127
------------ -----------
Other property and equipment ........................ 70,044,882 4,404,975
Less accumulated depletion, depreciation
and amortization ............................... (15,517,656) (1,260,605)
------------ -----------
$ 54,527,226 $ 3,144,370
------------ -----------
------------ -----------
</TABLE>
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED):
The Company's proved gas and oil reserves are located in the United
States. Proved reserves are those quantities of natural gas and crude oil which,
upon analysis of geological and engineering data, demonstrate with reasonable
certainty to be recoverable in the future from known gas and oil reservoirs
under existing economic and operating conditions (i.e. price and costs as of the
date the estimate is made). Proved developed (producing and non-producing)
reserves are those proved reserves which can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
gas and oil reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling units
offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation.
FINANCIAL DATA
The Company's gas and oil producing activities represent substantially
all of the business activities of the Company. The following costs include all
such costs incurred during each period, except for depreciation and amortization
of costs capitalized:
49
<PAGE>
COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997
----------- ----------
<S> <C> <C>
Acquisition of properties:
Proved......................................................................... $ --- $ 765,678
Unproved....................................................................... 63,511,000 242,205
Exploration costs................................................................. 13,412,133 1,861,432
Development costs................................................................. 7,114,820 153,938
----------- ----------
Total costs incurred........................................................ $84,037,952 $3,023,253
----------- ----------
----------- ----------
</TABLE>
CAPITALIZED COSTS:
<TABLE>
<CAPTION>
AT DECEMBER 31,
----------------------------
1998 1997
------------ ----------
<S> <C> <C>
Proved............................................................................ $ 14,006,244 $1,181,811
Unproved properties, subject to amortization...................................... 43,800,198 --
Unproved properties, not subject to amortization.................................. 10,835,056 2,054,037
Less accumulated amortization..................................................... (14,584,784) (438,044)
------------ ----------
Net capitalized costs....................................................... $ 54,056,714 $2,797,804
------------ ----------
------------ ----------
</TABLE>
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:
The estimates of proved producing reserves were estimated. Proved
reserves cannot be measured exactly because the estimation of reserves involves
numerous judgmental and arbitrary determinations. Accordingly, reserve estimates
must be continually revised as a result of new information obtained from
drilling and production history or as a result of changes in economic
conditions.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE AND
NATURAL GAS LIQUIDS
NATURAL GAS (MCF) (BARRELS)
---------------------------- ------------------------
YEARS ENDED DECEMBER 31, YEARS ENDED DECEMBER 31,
---------------------------- ------------------------
1998 1997 1998 1997
---------- ---------- --------- ---------
<S> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of period............................. 5,500,363 8,901,555 114,399 183,735
Purchases of minerals-in-place.................. --- --- --- ---
Sales of minerals-in-place...................... --- (159,528) --- (3,857)
Revisions of previous estimates................. (5,284,456) (3,129,076) (97,420) (59,121)
Extensions, discoveries and other additions..... 12,367,076 8,716 92,094 928
Production...................................... (653,316) (121,304) (8,878) (7,286)
---------- ---------- ------- -------
End of period................................... 11,929,667 5,500,363 100,195 114,399
---------- ---------- ------- -------
---------- ---------- ------- -------
Proved developed reserves:
Beginning of period............................. 521,345 985,524 24,358 46,420
End of period................................... 6,864,564 521,345 59,085 24,358
</TABLE>
Reserves of wells, which have performance history, were estimated
through analysis of production trends and other appropriate performance
relationships. Where production and reservoir data were limited, the volumetric
method was used and it is more susceptible to subsequent revisions.
50
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:
The standardized measure of discounted future net cash flows is based
on criteria established by Financial Accounting Standards Board Statement No.
69, "Accounting for Oil and Gas Producing Activities" and is not intended to be
a "best estimate" of the fair value of the Company's oil and gas properties. For
this to be the case, forecasts of future economic conditions, varying price and
cost estimates, varying discount rates and consideration of other than proved
reserves (i.e., probable reserves) would have to be incorporated into the
valuations. Future net cash inflows are based on the future production of proved
reserves of natural gas, natural gas liquids, crude oil and condensate as
estimated by petroleum engineers by applying current prices of gas and oil (with
consideration of price changes only to the extent fixed and determinable and
with consideration of the timing of gas sales under existing contracts or spot
market sales) to estimated future production of proved reserves. Average year
end prices used in determining future cash inflows for natural gas and oil for
the periods ended December 31, 1998 and 1997 were as follows: 1998 - $2.01 per
MCF-Gas, $9.03 per barrel-Oil; 1997 - $2.46 per MCF-Gas, $15.70 per barrel-Oil,
respectively. Future net cash flows are then calculated by reducing such
estimated cash inflows by the estimated future expenditures (based on current
costs) to be incurred in developing and producing the proved reserves and by the
estimated future income taxes. Estimated future income taxes are computed by
applying the appropriate year-end tax rate to the future pretax net cash flows
relating to the Company's estimated proved oil and gas reserves. The estimated
future income taxes give effect to permanent differences and tax credits and
allowances.
The following table sets forth the Company's estimated standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1998 1997
----------- -----------
<S> <C> <C>
Future cash inflows............................................................ $25,241,119 $15,752,040
Future development and production costs........................................ (8,478,613) (7,468,887)
Future income tax expenses..................................................... -- (365,224)
----------- -----------
Future net cash flows.......................................................... 16,762,506 7,917,929
Discount....................................................................... (4,242,485) (4,019,429)
----------- -----------
Standardized measure of discounted future net cash flows....................... $12,520,021 $3,898,500
----------- -----------
----------- -----------
</TABLE>
The following table sets forth changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1998 1997
----------- ------------
<S> <C> <C>
Standardized measure of discounted future cash flows-beginning of period....... $ 3,898,500 $ 16,758,544
Sales of oil and gas produced, net of operating expenses....................... (1,021,830) (312,198)
Net changes in sales prices and production costs............................... (4,459,331) (10,601,580)
Extensions, discoveries and improved recovery, less related costs.............. 13,358,762 30,952
Change in future development costs............................................. 5,135,315 (433,314)
Previously estimated development costs incurred during the year................ 2,515 162,610
Revisions of previous quantity estimates....................................... (1,957,356) (4,973,603)
Accretion of discount.......................................................... 402,566 2,169,632
Net change of income taxes..................................................... 127,157 4,810,619
Sales of minerals-in-place..................................................... - (371,728)
Changes in production rates (timing) and other................................. (2,966,277) (3,341,614)
----------- ------------
Standardized measure of discounted future cash flows-end of period............. $12,520,021 $ 3,898,500
----------- ------------
----------- ------------
</TABLE>
51
<PAGE>
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
52
<PAGE>
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT
The following table sets forth certain information regarding the
Company's directors and executive officers.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- ---------
<S> <C> <C>
David W. Berry(1)(4)................................. 49 Chairman of the Board
Alex M. Cranberg(1)(2)(5)............................ 44 Vice Chairman of the Board
Michael E. Johnson(1)(5)............................. 50 Director, President and Chief Executive Officer
Charles J. Smith(1)(4)............................... 72 Director
Alex B. Campbell(3)(4)............................... 41 Director
William D. Dodge, III(2)(6).......................... 46 Director
Jack P. Randall(2)(3)(5)............................. 49 Director
Hobart A. Smith(3)(6)................................ 62 Director
David B. Christofferson.............................. 50 Senior Vice President, Secretary and General Counsel
</TABLE>
- -----------
(1) Member of the Executive Committee.
(2) Member of the Audit Committee.
(3) Member of the Compensation Committee.
(4) Director whose term expires in 1999.
(5) Director whose term expires in 2000
(6) Director whose term expires in 2001
DAVID W. BERRY has served as President of the Company since the
incorporation of its predecessor in August 1988 and until May 14, 1998, and
has served as Chairman of the Board of Directors since 1991. In 1978, he
formed Berry Petroleum Corporation, which was a regional natural gas and oil
exploration company. In 1976 he co-founded Vulcan Energy Corporation, a
Tulsa, Oklahoma based exploration and production company. Mr. Berry has
served as the State Finance Chairman of the Oklahoma State Republican Party,
as a Trustee for the Oklahoma Museum of Art and on the United States
Senatorial Trust Committee. Mr. Berry is a member of the 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
53
<PAGE>
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.
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, 56, 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.
LINDA D. SCHIBI, 42, is Vice President-Land. Mrs. Schibi joined EPC in
1978 and became the Company's Land
54
<PAGE>
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 production. She is a Certified Petroleum Landman. She attended Del
Mar College.
DALE W. ALEXANDER, 43, is Vice President-Exploitation. He served EPC as
a consultant in the area of reservoir and exploitation engineering from 1991
until May 14, 1998, when he became the Company's Vice President--Exploitation.
Mr. Alexander is responsible for determining pre-drill economics, risk weighting
drilling projects and coordination of reserve reports. From 1988 to 1991, he was
with Kamlock Oil & Gas Company. He was an exploitation/reservoir engineer for
EPC from 1983 to 1988. He also has worked for Champlin Petroleum Company, and
Union Oil of California. Mr. Alexander has a BS in Petroleum Engineering from
the University of Texas.
MICHAEL E. MOORE, 41, 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, 43, 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.
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Section 16(a) of the Exchange Act requires the Company's directors,
executive officers and persons who own more than 10% of a registered class of
the Company's equity securities, to file reports of ownership on Form 3 and
changes in ownership on Form 4 or 5 with the Commission. Such officers,
directors and 10% shareholders also are required by Commission rules to furnish
the Company with copies of all Section 16(a) reports they file. Based solely on
its review of the copies of such forms received by it, or written
representations from certain reporting persons that they were not required to
file a Form 5, the Company believes that, during the fiscal year ended December
31, 1998, its officers, directors and 10% shareholders complied with all Section
16(a) filing requirements applicable to such individuals.
ITEM 10. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth the total remuneration paid during 1998,
1997 and 1996 to the individuals who served as Chief Executive Officer of the
Company during 1998 and the Company's other most highly compensated officers
who received compensation in excess of $100,000 during 1998.
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
----------------------
ANNUAL COMPENSATION(1) AWARDS PAYOUTS
---------------------------- ----------------------
AWARDS OF LTIP ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS (2) PAYOUTS COMPENSATION
- ------------------------------------------------------------- ---------------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Michael E. Johnson(3)........ 1998 $125,000 ------ ------ ------ ------
President and
Chief Executive Officer
David W. Berry(4)............... 1998 $147,079 ------ ------ ------ $264,000(5)
Chairman of the Board 1997 134,400 ------ 32,000(6) $44,965(7) ------
1996 124,000 ------ 20,000(6) 20,145(7) ------
David B Christofferson.......... 1998 121.606 ------ ------ ------ $224,000(5)
Senior Vice President 1997 112,000 ------ 58,667(6) $47,888(8) ------
Principal Financial Officer 1996 103,000 ------ 16,667(6) 22,469(8) ------
</TABLE>
55
<PAGE>
- ----------------------------
(1) Does not include perquisites and other personal benefits which are less
than either $50,000 or 10% of the total of annual salary and bonus.
(2) Represents the number of shares of Common Stock issuable pursuant to
vested and non-vested stock options.
(3) Mr. Johnson became the Chief Executive Officer of the Company on May
14, 1998.
(4) Mr. Berry served as Chief Executive Officer through May 14, 1998.
(5) Upon the closing of the Acquisitions, previously existing incentive
agreements and contract settlement agreements with both Mr. Berry and
Mr. Christofferson required total payments of $264,000 to Mr. Berry and
$224,000 to Mr. Christofferson. These amounts were paid 50% in cash and
50% pursuant to promissory notes due in January of 1999 to each
individual. See "Certain Transactions".
(6) 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.
(7) 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.
(8) 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.
OPTION GRANTS OR REPRICINGS
There were no option grants or repricings made in 1998 to the
individuals named in the Summary Compensation Table above.
OPTION EXERCISE AND YEAR-END VALUES
The following table sets forth certain information as of December 31,
1998 with respect to the unexercised options to purchase Common Stock to the
individuals named in the Summary Compensation Table above.
None of such individuals exercised any stock options during 1998.
<TABLE>
<CAPTION>
VALUE OF UNEXERCISED
NUMBER OF UNEXERCISED IN-THE MONEY-OPTIONS AT
OPTIONS AT DECEMBER 31, 1998 DECEMBER 31, 1998 (1)
-----------------------------------------------------------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- ----------- -------------- ----------- --------------
<S> <C> <C> <C> <C>
David W. Berry...................... 32,000 ------ ----- ------
David B Christofferson............. 58,667 ------ ----- ------
</TABLE>
- --------------
(1) Based on the last sale price of the Common Stock on the Nasdaq
Small-Cap Market on December 31, 1998 of $1.875.
OPTION PLANS
Employee Option Plan-1997. The 1997 Plan authorizes the issuance of
up to 115,892 options to purchase one share of Common Stock. Options to
purchase 94,001 shares are currently outstanding at exercise prices ranging
from $3.78 per share to $7.68 per share. There are no other option plans
currently in effect.
DIRECTORS' COMPENSATION
No directors' compensation was paid in 1998. A directors' compensation
plan is to be finalized in the second quarter of 1999 which is anticipated to
include certain compensation for 1998 services.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information, as of March 26,
1999, with respect to the Common Stock owned by (i) each person known by
management to own beneficially more than 5% of the Company's outstanding Common
Stock; (ii) each of the Company's Directors and each executive officers who
received compensation in 1998 in excess of $100,000; and (iii) all Directors and
executive officers of the Company as a group. Unless otherwise noted, the
persons named below have sole voting and investment power with respect to such
shares.
56
<PAGE>
<TABLE>
<CAPTION>
Number of Percent of
Name of Beneficial Owner Shares (1) Class (2) (3)
------------------------ ---------- -------------
<S> <C> <C>
Esenjay Petroleum Corporation(4).............. 5,177,761(5) 32.78%
Aspect Resources LLC(6)....................... 4,386,856(7) 27.76%
David W. Berry(13)............................ 162,155(8) 1.03%
Alex M. Cranberg(6)........................... 4,398,756(9) 27.83%
Michael E. Johnson(4)......................... 5,260,261(10) 33.30%
Charles J. Smith(4)........................... 5,263,761(10) 33.32%
Alex B. Campbell(6)........................... ------ *
William D. Dodge, III(13)..................... ------ *
Jack P. Randall(13)........................... ------ *
Hobart A. Smith(13)........................... 1,667 *
David B Christofferson(13).................... 68,000(11) *
All executive officers and Directors as
a group (9 persons)......................... 412,222(12) 2.60%
</TABLE>
- ----------------------
* Less than 1%
(1) Includes all shares of Common Stock with respect to which each person,
executive officer or Director who directly, through any contract,
arrangement, understanding, relationship or otherwise, has or shares
the power to vote or to direct voting of such shares or to dispose or
to direct the disposition of such shares. Includes shares that may be
purchased under stock options exercisable within 60 days.
(2) Based on 15,784,834 shares of Common Stock outstanding at March 26,
1999, plus, for each beneficial owner, those number of shares
underlying exercisable options held by each executive officer or
Director.
(3) Percent of class for any Stockholder listed is calculated without
regard to shares of Common Stock issuable to others upon exercise of
outstanding stock options. Any shares a Stockholder is deemed to own by
having the right to acquire by exercise of a stock option or warrant
are considered to be outstanding solely for the purpose of calculating
that Stockholder's ownership percentage.
(4) Address: c/o Esenjay Exploration, Inc., North 500 Water Street, Suite
1100 South, Corpus Christi, Texas 78471.
(5) Includes 12,500 shares of Common Stock issuable upon the exercise of
warrants.
(6) Address: 511 16th Street, Suite 300, Denver, Colorado 80202.
(7) Includes 18,750 shares of Common Stock issuable upon the exercise of
warrants.
(8) Includes 32,000 shares of Common Stock issuable upon the exercise of
stock options that are currently exercisable.
(9) Includes (i) 11,900 shares of Common Stock owned and (ii) 4,386,856
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.
(10) Includes (i) 82,500 shares owned and (ii) 5,165,261 shares of Common
Stock owned by EPC, 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.
(11) Includes 58,667 shares of Common Stock issuable upon the exercise of
stock options that are currently exercisable.
(12) Includes 90,667 shares issuable pursuant to stock options held by
executive officers and Directors that are currently exercisable. Does
not include any shares of Common Stock as to which beneficial ownership
is disclaimed.
(13) Address: c/o Esenjay Exploration, Inc., 500 Dallas, Suite 2920,
Houston, Texas 77002.
COMPLIANCE WITH SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING REQUIREMENTS
Section 16(a) of the Securities and Exchange Act of 1934 requires that
Company's Directors, executive officers and any persons who own more than 10% of
a registered class of the Company's equity securities to file with the
Securities and Exchange Commission (the "SEC") reports of ownership and changes
in ownership of Common Stock and other equity securities of the Company.
Officers, Directors and greater than 10% stockholders are required by SEC
regulation to furnish the Company with copies of all Section 16(a) forms they
file.
57
<PAGE>
Based solely on review of the copies of such reports furnished to the
Company or written representations that no other reports were required, the
Company believes that, during the 1998 fiscal year, all filing requirements
applicable to its executive officers, Directors and greater than 10%
stockholders were compiled on a timely basis.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company and Aspect Management Corporation, the manager of Aspect
("Aspect Management"), have entered into a Geotechnical Services Consulting
Agreement on May 14, 1998, pursuant to which Aspect Management performs
geotechnical services for the Company. The Company and Aspect Management also
entered into a Land Service Consulting Agreement on May 14, 1998, pursuant to
which Aspect Management provides certain land related services to 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. Under the Geotechnical Consulting Agreement,
Aspect Management must obtain the Company's approval to enter into any related
contract or agreement that has a cost exceeding $50,000 net to the Company. The
Company must pay Aspect Management for services rendered in an amount equal to
Aspect's employee costs, overhead costs and general and administrative costs
associated with the services rendered thereunder. The agreements terminate on
May 14, 2002, unless terminated by either party with 90 days' written notice to
the other party.
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 a
credit 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 another 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 above referenced credit
facilities.
Each of Messrs. Berry and Christofferson (each an "Employee") 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 closed a significant
corporate transaction, and the Employee did 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 were 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 were intended to satisfy the Employees employment
contracts. Incentive Payments were 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 were 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 occurred, 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.
The Acquisitions constituted a significant corporate transaction
pursuant to which the Incentive Payments and Contract Settlement Payments were
payable to Mr. Berry and Mr. Christofferson. Pursuant to the Incentive
Agreements and Contract Settlement Agreements the Company has paid Mr. Berry and
Mr. Christofferson the above described note payments. Mr. Berry and Mr.
Christofferson have no further contractual obligations to the Company
58
<PAGE>
other than confidentiality obligations and any contractual arrangements they
may negotiate with the Company in the future.
The Company's outstanding advances to employees and affiliates of the
Company at December 31, 1998 and 1997 was $963,700 and $105,171, respectively.
The December 31, 1998 and 1997 receivables include approximately $47,787 from an
affiliated partnership for which the Company serves as the managing general
partner. In addition, the December 31, 1998 balance includes a $915,342
receivable from EPC primarily related to joint interest billings to EPC. In
addition, amounts payable of $134,400 and $112,000 were due to David W. Berry
and David B Christofferson, respectively, in conjunction with the settlement of
their prior employment contracts, which amounts were paid in January 1999.
In addition, at December 31, 1998 the Company had a net account
payable to Aspect Resources LLC in the amount of $4,322,548. It has also
entered into an agreement to sell to Aspect a 12.5% (of 100%) interest in the
Caney Creek Project, a 12% (of 100%) interest in the Gillock Project, and all
of the Company's undeveloped property interests in the West Beaumont project
area for $2,610,000. Closing is scheduled for the second quarter of 1999.
Proceeds from the sale will be used to settle amounts due Aspect. In that
Aspect is a related party, closing is subject to receipt of an independent
fairness opinion which management believes will be timely obtained.
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.
59
<PAGE>
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
Exhibit Name of Exhibit
- ------- ---------------
<S> <C>
2(a) Acquisition Agreement and Plan of Exchange dated as of January 19,
1998, by and among Frontier Natural Gas Corporation, Esenjay Petroleum
Corporation, and Aspect Resources LLC as incorporated by reference to
the Company's Annual Report on Form 10-KSB for the fiscal year ended
December 31, 1997 dated April 6, 1998, wherein the same appears as
Exhibit 2.
2(b) First Amendment to Acquisition Agreement and Plan of Exchange dated as
of April 20, 1998, by and among Frontier Natural Gas Corporation,
Esenjay Petroleum Corporation, and Aspect Resources LLC as incorporated
by reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 10(x).
2(c) Second Amendment to Acquisition Agreement and Plan of Exchange dated as
of May 13, 1998, by and among Frontier Natural Gas Corporation, Esenjay
Petroleum Corporation, and Aspect Resources LLC as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 10(y).
2(d) Plan and Agreement of Merger dated as of May 14, 1998, by and between
Esenjay Exploration, Inc., a Delaware corporation, and Frontier Natural
Gas Corporation as incorporated by reference to the Company's Proxy
Statement filed with the Securities and Exchange Commission on April
24, 1998, wherein the same appeared as Appendix F.
3(a) Certificate of Incorporation of the Company as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 3(a).
3(b) By-Laws of the Company as incorporated by reference to the Company's
Registration Statement number 333-53581 dated May 21, 1998 wherein the
same appeared as Exhibit 3(c).
4 See Articles V, VI and X of the Company's Certificate of Incorporation
and Articles I, II, V and VI of the Company's By-Laws as provided at
Exhibits 3(a) and 3(b) above.
10(a) Contract Settlement Agreement between Frontier Natural Gas Corporation
and David W. Berry dated effective January 1, 1998, as incorporated by
reference to the Company's Annual Report on Form 10-KSB for the fiscal
year ended December 31, 1997 dated April 6, 1998, wherein the same
appears as Exhibit 10(b).
10(b) Contract Settlement Agreement between Frontier Natural Gas Corporation
and David B Christofferson dated effective January 1, 1998, as
incorporated by reference to the Company's Annual Report on Form 10-KSB
for the fiscal year ended December 31, 1997 dated April 6, 1998,
wherein the same appears as Exhibit 10(d).
10(c) $20,000,000 Amended and Restated Credit Agreement dated as of October
13, 1998, between Esenjay Exploration, Inc. as the borrower and Bank of
America NT&SA as the lender, as incorporated by reference to the
Company's Annual Report on Form 10-KSB for the fiscal year ended
December 31, 1998 dated April 14, 1999, wherein the same appears as
Exhibit 10(c).
10(d) Credit Agreement by and between Esenjay Exploration, Inc. and Duke
Energy Financial Services, Inc. dated as of January 28, 1999, as
currently in effect, as incorporated by reference to the Company's
Annual Report on Form 10-KSB for the fiscal year ended December 31,
1998 dated April 14, 1999, wherein the same appears as Exhibit 10(d).
60
<PAGE>
10(e) Loan Agreement by and between Frontier Natural Gas Corporation and 420
Energy Investments, Inc. dated March 1, 1996, as currently in effect as
incorporated by reference to the Company's Annual Report on Form 10-KSB
for the fiscal year ended December 31, 1995 dated March 29, 1996,
wherein the same appears as Exhibit 10(r).
10(f) Employee Option Plan-1997 as currently in effect as incorporated by
reference to the Company's Annual Report on Form 10-KSB for the fiscal
year ended December 31, 1997 dated April 6, 1998, wherein the same
appears as Exhibit 10(o).
10(g) Warrant Agreement between Frontier Natural Gas Corporation and Gaines,
Berland Energy Fund, L.P. dated January 14, 1998, as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 10(q).
10(h) Warrant Agreement between Frontier Natural Gas Corporation and Esenjay
Petroleum Corporation dated January 14, 1998, as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 10(r).
10(i) Warrant Agreement between Frontier Natural Gas Corporation and Aspect
Resources LLC dated January 14, 1998, as incorporated by reference to
the Company's Registration Statement number 333-53581 dated May 21,
1998 wherein the same appeared as Exhibit 10(s).
10(j) Warrant Agreement between Frontier Natural Gas Corporation and Gaines,
Berland Energy Fund, L.P. dated January 23, 1998, as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 10(t).
10(k) Warrant Agreement between Frontier Natural Gas Corporation and Esenjay
Petroleum Corporation dated January 23, 1998, as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 10(u).
10(l) Warrant Agreement between Frontier Natural Gas Corporation and Aspect
Resources LLC dated January 23, 1998, as incorporated by reference to
the Company's Registration Statement number 333-53581 dated May 21,
1998 wherein the same appeared as Exhibit 10(v).
11* Statement of Earnings per Share
21* Subsidiaries of Registrant.
27* Financial Data Schedule.
(b) Reports on Form 8-K.
None
</TABLE>
- -------------------
*Filed herewith
61
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13, or 15(d) of the Securities
and Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
ESENJAY EXPLORATION, INC.
Date: April 30, 1999 By: /s/ Michael E. Johnson
------------------------------------
Michael E. Johnson, President,
Chief Executive Officer and Director
Pursuant to the requirements of Section 13, or 15(d) of the Securities
and Exchange Act of 1934, the registrant has duly caused this report to be
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
Date: April 30, 1999 /s/ David B Christofferson
----------------------------------------
David B Christofferson, Senior Vice
President General Counsel and Chief
Financial Officer
Date: April 30, 1999 /s/ Howard E. Williams
----------------------------------------
Howard E. Williams, Vice President and
Principal Accounting Officer
Date: April 30, 1999 /s/ David W. Berry
----------------------------------------
David W. Berry, Chairman and Director
Date: April 30, 1999 /s/ Charles J. Smith
----------------------------------------
Charles J. Smith, Director
Date: April 30, 1999 /s/ Alex M. Cranberg
----------------------------------------
Alex M. Cranberg, Director
Date: April 30, 1999 /s/ Alex B. Campbell
----------------------------------------
Alex B. Campbell, Director
62
<PAGE>
EXHIBIT 11 TO FORM 10-KSB
COMPUTATION OF EARNINGS PER COMMON SHARE AND COMMON SHARE EQUIVALENTS
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------
1998 1997
------------ -----------
<S> <C> <C>
BASIC EARNINGS PER SHARE
Weighted average common shares outstanding 9,882,227 1,646,311
------------ -----------
------------ -----------
Basic loss per share $ (2.97) $ (3.07)
------------ -----------
------------ -----------
DILUTED EARNINGS PER SHARE
Weighted average common shares outstanding 9,882,227 1,646,311
Share issuable from assumed conversion of
common share options and warrants - 1,338
------------ -----------
Weighted average common shares outstanding, as adjusted 9,882,227 1,647,649
------------ -----------
------------ -----------
Diluted loss per share $ (2.97) $ (3.07)
------------ -----------
------------ -----------
EARNINGS FOR BASIC AND DILUTED COMPUTATION
Net income $(29,321,347) $(4,953,803)
Preferred shares dividend (48,138) (103,153)
------------ -----------
Net income to common shareholders (basic and diluted
earnings per share computation) $(29,369,485) $(5,056,956)
------------ -----------
------------ -----------
</TABLE>
This calculation is submitted in accordance with Regulation S-K; although it
is contrary to paragraphs 13 through 16 of the Financial Accounting Standards
Board's Statement of Financial Standard No. 128, because it produces an
antidilutive result.
63
<PAGE>
EXHIBIT 21 TO FORM 10-KSB
The subsidiaries of the Registrant are:
<TABLE>
<CAPTION>
Name State of Incorporation
- ---- ----------------------
<S> <C>
Frontier Acquisition Corp. Oklahoma
</TABLE>
64
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 646,200
<SECURITIES> 0
<RECEIVABLES> 3,558,617
<ALLOWANCES> (348,984)
<INVENTORY> 0
<CURRENT-ASSETS> 4,941,955
<PP&E> 70,044,882
<DEPRECIATION> (15,517,656)
<TOTAL-ASSETS> 59,916,272
<CURRENT-LIABILITIES> 15,898,490
<BONDS> 7,500,000
0
0
<COMMON> 157,849
<OTHER-SE> 35,164,739
<TOTAL-LIABILITY-AND-EQUITY> 59,916,272
<SALES> 1,372,002
<TOTAL-REVENUES> 1,716,473
<CGS> 0
<TOTAL-COSTS> 30,417,699
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 620,121
<INCOME-PRETAX> (29,321,347)
<INCOME-TAX> 0
<INCOME-CONTINUING> (29,321,347)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (29,321,347)
<EPS-PRIMARY> (2.97)
<EPS-DILUTED> (2.97)
</TABLE>
