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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, 1999
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission file number: 0-22782
ESENJAY EXPLORATION, INC.
(Exact name of small business issuer in its charter)
DELAWARE 73-1421000
(State of incorporation) (I.R.S. Employer Identification Number)
500 N. WATER STREET, SUITE 1100
CORPUS CHRISTI, TEXAS 78471
(Address of registrant's principal executive offices, including zip code)
Registrant's telephone number, including area code: (361) 883-7464
Securities registered under Section 12(b) of the Exchange Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
None None
Securities registered under Section 12(g) of the Exchange Act:
COMMON STOCK
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. [ ]
State issuer's revenues for its most recent fiscal year: $12,566,165
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 $17,686,299 on March 27, 2000 (based on the last sales price
of $2.031 per share as reported on the NASDAQ Stock Market).
18,857,251 shares of the registrant's common stock were outstanding as
of April 28, 2000.
DOCUMENTS INCORPORATED BY REFERENCE
REGISTRANT'S PROXY STATEMENT FOR ITS 2000 ANNUAL MEETING OF SHAREHOLDERS
IS INCORPORATED BY REFERENCE INTO PART III
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ESENJAY EXPLORATION, INC.
FOR YEAR ENDED DECEMBER 31, 1999
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.............................................................................. 18
3. Legal Proceedings.................................................................................... 20
4. Submission of Matters to a Vote of Security Holders.................................................. 20
PART II
5. Market for Common Equity and Related Stockholder Matters............................................. 21
6. Management's Discussion and Analysis or Plan of Operation............................................ 22
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................................................................ 51
PART III
9. Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act.................................................. 52
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 22 of
this Form 10-KSB/A.
ITEM 1. DESCRIPTION OF BUSINESS
GENERAL
THE COMPANY
Esenjay Exploration, Inc. (the "Company") is an independent energy
company engaged in the exploration for and development of natural gas and oil.
The Company has assembled a diverse inventory of technology enhanced natural gas
and oil exploration projects primarily along the Texas and Louisiana Gulf Coast
(the "Exploration Projects"). These Exploration Projects include 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 September of 1999 the Company acquired 3DX
Technologies Inc., pursuant to which acquisition it expanded its ownership in
certain of its exploration projects, added interests in other projects, and
expanded its technical staff.
OVERVIEW OF CURRENT ACTIVITIES AND RECENT EVENTS. Most of the
Exploration Projects have been enhanced with 3-D seismic data in conjunction
with computer aided exploration ("CAEX") technologies. The 3-D seismic data
acquired to date covers approximately 1,844 square miles, with additional 3-D
seismic surveys currently in process. A significant number of the Exploration
Projects have reached the drilling stage, and the Company has budgeted
approximately $18 million to fund its drilling and completion budget in 2000. It
has also budgeted approximately $8 million for additional land and geophysical
costs for a total 2000 capital expenditure budget of approximately $26 million.
The budget is projected to fund the Company's net cost in over 40 wells. The
Company currently has capital resources to substantially fund its 2000 capital
expenditures budget. (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, which utilizes the successful efforts method of
accounting, entered 2000 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 $1,815,637 per month in oil and gas revenues in
the fourth quarter of 1999. This revenue number grew rapidly in the second half
of 1999 as wells drilled began to rapidly come on line. Revenues are expected to
continue to increase in 2000. In addition, since December 31, 1999, the Company
has closed a long term $29,000,000 financing facility with $21,000,000 available
with Deutsche Bank AG, New York Branch, which repaid all existing long term debt
of approximately $15.8 million, including $11,013,162 which was classified as
current at December 31, 1999. It has also closed a sale of project interests to
an industry partner for a total of $10,940,000 ($10,585,981 net after
transaction fees) to the Company. The closed financing, combined with the closed
project interest sale, enhanced working capital and will significantly
contribute to the Company's 2000 capital expenditure plan. (See "See
Management's Discussion and Analysis - Liquidity and Capital Resources"). A
survey of the Company's history is set forth below.
OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH DECEMBER 31,
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
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Gulf Coast 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 transactions
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.
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.
On Exploration Projects acquired in 1998 pursuant to the Acquisitions,
the Company participated in the drilling of twenty-four wells through December
31, 1998 with working interests, which range from 8% to 79%. Out of those
twenty-four wells drilled, thirteen wells have been completed and eleven were
dry holes. Several of the successful wells went into production late in the
third quarter of 1998, and in the fourth quarter of 1998.
OVERVIEW OF 1999 ACTIVITIES. As a result of the above-described
acquisitions, restructuring, and the underwritten offering, the Company believed
it was, and believes it continues to be, positioned for a period of significant
exploration activity on its technology enhanced projects. Many of the projects
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, required several
years and the investment of significant capital. Management believes the
acquisition of projects at this advanced stage has not only reduced the drilling
risk, but should allow the Company to consistently drill on a broad array of
exploration prospects in 1999 and subsequent years.
In the first half of 1999, the Company completed a review of each of
its operating departments in order to identify areas where it could increase
efficiency and/or reduce costs. As a result, it has implemented personnel and
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procedural changes in the accounting, land and operations departments. These
changes increased certain third quarter costs due to consultants fees,
employment severance packages, and new systems implementation. However, as a
result, the Company expects to achieve increased cost efficiency in certain
general, administrative, management and operational areas.
In 1999, the Company participated in 29 new wells which reached total
depth and were logged during the year. Of the total wells drilled and logged in
1999, 20 were producing as of March 28, 2000, 2 are scheduled to commence
production upon completion and pipeline connections, 7 were dry holes, 1 of
which logged productive but had mechanical completion problems and will be
redrilled. Only 2 of the 1999 wells were producing as of July 1, 1999, and as a
result the Company's net daily oil and gas production increased substantially
throughout the third and fourth quarters. Based upon estimated sustainable flow
rates, the 1999 wells helped to increase the Company's net daily production to
approximately 532 barrels of oil per day and 14,605 million cubic feet of
natural gas per day as of December 1999.
The Company's net cost in the 29 wells was approximately $8,652,439 for
drilling and completion, not including certain prior expenditures incurred at
the project level for land and seismic. It should be noted that the Company
defines a "project" as a distinct 3-D seismic data area which often comprises
several distinct exploratory "prospects". Net reserves attributable to the 29
wells drilled in 1999 total 18,466,712 MCFE including 1999 production and
December 31, 1999 remaining reserves. On a present value basis, the Company
achieved a present value in excess of four times the 1999 drilling and
completion costs expended.
The Company ended 1999 having gone from nominal third quarter 1998 gas
and oil revenues of approximately $35,000 per month and large operating cash
flow deficits to a company which averaged $1,815,637 per month in net oil and
gas revenues and associated hedging revenues from commodity transactions in the
fourth quarter of 1999. This number increased significantly as the wells drilled
in 1999 continued to come on line. This allowed the Company to achieve positive
operating cash flow (before capital expenditures, and before the costs of
acquisition of new 3-D seismic data, and changes in working capital) in the
third quarter, which operating cash flow increased in the fourth quarter. As a
result of this trend, approximately 56% of the Company's 1999 gas and oil
revenue were attributable to the fourth quarter of the year.
On May 12, 1999, the Company announced that it had entered into a Plan
and Agreement of Merger with 3DX Technologies, Inc. ("3DX") which provided for
the merger of 3DX into the Company. The shareholders of both companies approved
the transaction at their respective meetings on September 23, 1999 and the
merger was consummated the same day. The terms of the merger provided for 3DX
shareholders to receive, at their election, either (i) the issuance of one share
of Esenjay common stock for 3.25 shares of 3DX common stock; or (ii) the
issuance of a new Esenjay convertible preferred stock at a ratio of one share of
Esenjay convertible preferred stock for each 2.75 shares of 3DX common stock.
The preferred stock does not require payment of dividends. Approximately 91% of
the 3DX common shares converted into Esenjay common stock and approximately 9%
were converted into Esenjay convertible preferred stock. As a result, Esenjay
issued approximately 2,906,800 new shares of common stock and approximately
357,000 shares of convertible preferred stock.
The convertible preferred stock may be redeemed at Esenjay's sole
option until September 23, 2000 at $1.925 per share. If not redeemed by that
time, the preferred will automatically convert into one share of Esenjay common
stock on October 1, 2000 if the average closing price of Esenjay common stock is
greater than or equal to $1.875 during the month of September 2000. If the
Esenjay common stock averages less than $1.875 in September of 2000, the
preferred holder has the right, during the month of October of 2000, to "put"
the shares to Esenjay. If put, Esenjay will then have the right to retire the
convertible preferred stock for $1.65 in cash or for common stock with the
number of shares of common stock adjusted based upon a formula set out in the
merger agreement. The convertible preferred stock is scheduled to be converted
or redeemed not later than November 1, 2000. Prior to that time no dividends
accrue or are required to be paid other than as would participate with any
common stock dividends, which common stock dividends are not anticipated to be
declared.
OVERVIEW OF 2000 ACTIVITIES. The Company believes it enters 2000 in a
position to continue to expand its exploration activities on its
technology-enhanced projects. By utilizing its increased capital available to it
from cash flow, financings and industry partner transactions, the Company
intends to pursue an aggressive exploration budget in all of its major trends of
activity. The Company's net daily production approximated 530 barrels of oil per
day and
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13,767 Mcf natural gas per day in March of 2000. This net production is after a
reduction of 6 barrels of oil per day and 1,981 Mcf of natural gas per day
attributable to the sale of interests in the Raymondville Project as described
below in this paragraph. The Company has also successfully improved its working
capital and cash resources. On February 7, 2000, it announced the closure of a
$29 million credit facility with Deutsche Bank AG, New York Branch. Initial
availability pursuant to the facility was $21 million with a borrowing base
adjustment scheduled for the second quarter of 2000. A portion of the available
proceeds was utilized to retire approximately $15.8 million of previously
existing debt with Bank of America and Duke Energy Financial Services, Inc., of
which approximately $11 million was classified as the current portion of
long-term debt. The amount outstanding under the new facility was all classified
as long term debt. In addition, the Company sold approximately 84.39% of its
interest in its Raymondville Project in Willacy County to Cody Texas, L.P. for
cash proceeds of $10,940,000 ($10,585,981 net of transaction fees). The sale
closed on March 20, 2000 but was effective as of January 1, 2000. Pursuant to
this sale the Company sold 3,462,967 MCFE of its reserves classified as proven
as of December 31, 1999. Its borrowing base availability with Deutsche Bank was
not reduced. The combination of these two financing transactions provided $15.8
million in net additional cash resources (after repayment of existing debt) and
created significant positive working capital for the Company. As a result of its
current cash flow and the impact of these two transactions, the Company believes
it is well positioned to fund its 2000 drilling activities, the results of which
are intended to help continue the upward trends of increasing cash flow and
reserves. The Company will look to a variety of sources to further supplement
its capital expenditures budget, including its credit facilities and sales of
additional promoted project interests to industry partners, as it seeks to
maximize its interests and manage its risks while aggressively pursuing its
exploration projects.
The Company has budgeted $18,000,000 in drilling and completion
expenditures on interests in over 40 wells and an additional $8,000,000 in land
and new seismic costs in 2000. The budgeted drilling and completion
expenditures, which are primarily on exploratory wells, compares to total
drilling and completion expenditures of approximately $8,652,439 in 1999 when
the Company had less capital available. Through this exploration program, the
Company believes it can continue its 1999 trends of rapid growth in net
production, net revenues, operating cash flow, and net gas and oil reserves
throughout the year 2000 and beyond. It believes that certain of its planned
2000 exploratory wells represent the highest upside potential to which the
Company has been exposed.
As of March 27, 2000, the Company has approximately 18,770,000 total
shares of common stock and 357,000 total shares of preferred stock outstanding.
It employs 40 full time employees, including 12 in its geological and
geophysical departments, 7 in its operations department, and 11 in its land
department. Its focus continues to be the implementation of its business
strategy as set forth in this section.
SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes
the successful efforts method of accounting. Under this method it expenses its
exploratory dry hole costs and the field acquisition costs of 3-D seismic data
as incurred. The undeveloped properties, which were acquired pursuant to the
Acquisitions, were comprised primarily of interests in unproven 3-D seismic
based projects, and were recorded in May of 1998 at an independently estimated
fair market value of $54.2 million as determined by Cornerstone Ventures, L.P.,
a Houston, Texas based investment banking firm. Pursuant to the successful
efforts method of accounting, the Company is amortizing such initial costs of
unproved properties on a straight-line basis over a period not to exceed
forty-eight months, as well as recognizing property specific impairments. As of
December 31, 1999 the unamortized balance was $13,448,700. Hence significant
non-cash charges have depressed reported earnings of the Company and will likely
continue to do so in 2000; however, the non-cash charges will not affect cash
flows provided by operating activities nor the ultimate realized value of the
Company's natural gas and oil properties.
As a result of the tax rules applicable to the Acquisitions, the
Company will likely not be able to fully use its existing net operating loss
carry forward in the future.
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
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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 more accurately map structural
features to detect seismic anomalies that are not apparent in 2-D
seismic surveys. The Company believes that 3-D seismic technology, if
properly used, will reduce drilling risks and costs by reducing the
number of dry holes, optimizing well locations and reducing the number
of wells required to exploit a discovery. The Company believes that 3-D
seismic surveys are particularly suited to its Exploration Projects
along the Texas and Louisiana Gulf Coasts.
EXPERIENCED TECHNOLOGICAL TEAM. The Company maintains an experienced
technical staff, including engineers, geologists, geophysicists,
landmen and other technical personnel. After the Acquisitions, the
Company hired most of EPC's technical personnel, who, in some
instances, have worked together for over 15 years. It further expanded
its technical staff when it acquired 3DX in September of 1999. In
addition, the Company has 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
sizable gas accumulations (generally 8,000 to 12,500 feet) and that
also are conducive to direct hydrocarbon detection, but not so deep as
to be highly exposed to the greater mechanical risks and drilling costs
incurred in the deep plays in the region. In conjunction with
interpreting the 3-D seismic and CAEX data relating to the Company's
moderate depth wells, the Company 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 controlling interest in many of
the Exploration Projects, including proprietary interests in most of
the 3-D seismic data relating to those projects. As a result, the
Company will often be able to influence the areas to explore, manage
the land permitting and option process, determine seismic survey areas,
oversee data acquisition and processing, prepare, integrate and
interpret the data and identify each prospect drillsite. In addition,
the Company will likely be the operator of a majority of the wells
drilled within the Exploration Projects.
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EXPLORATION PROJECTS
Most of the Exploration Projects are concentrated within the Frio,
Wilcox, Texas Hackberry and Yegua core project areas. The Frio core area
generally is in the middle Texas Gulf Coast where the Company believes Frio
targets exist at moderate depths. The Wilcox core area generally is in the
middle Texas Gulf Coast in an area the Company believes to have prospects for
Wilcox sand exploration. The Texas Hackberry core area is located in Jefferson
and Orange Counties, Texas, in an area which the Company believes offers
drilling opportunities in the Hackberry formations, as well as Miocene and
deeper Vicksburg sands. The Yegua trend extends from San Patricio County in
Texas through Beauregard and Calcasieu Parishes in Louisiana. The Company became
active in two portions of this trend in 1999. 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. Because each
Exploration Project consists of a bundle of assets which may or may not include
a working interest in the project, the Company's Project Interest simply
represents the Company's proportional ownership in the bundle of assets that
constitute the Exploration Project. Therefore, the Company's Project Interest in
an Exploration Project should not be confused with the working interest that the
Company will own when a given well is drilled. It is possible that while the
Company may own a 50.0% Project Interest, it may only be entitled to 25.0% of
the working interest involved in the Exploration Project. Each Exploration
Project represents a negotiated transaction between the project partners. The
Company's working interest may be higher or lower than its Project Interest.
Certain projects are subject to an agreement with Seagull Energy E&P,
Inc. ("Seagull"), a subsidiary of Ocean Energy, Inc., which agreement provides
an option in favor of Seagull to acquire 50% of the Company's unproven interests
in the Mikeska and Hall Ranch projects for $6.5 million, plus, at Seagull's
option, 50% of the Company's unproven interests in the Orangedale, Verdad,
Hordes Creek and Riverdale projects for an additional $2.0 million. The option
must be exercised within 45 days of plugging or completion of two wells
anticipated to be drilled in the second quarter of 2000. (Said agreement is
referred to herein as the "Seagull Option Agreement").
The following table sets forth certain information about each of the
Exploration Projects:
EXPLORATION PROJECTS
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ACRES LEASED OR UNDER OPTION AT SQUARE MILES OF
MARCH 27, 2000(1) 3-D SEISMIC DATA
PROJECT PROJECT COMPANY RELATING TO PROJECT
PROJECT AREAS GROSS NET NET PROJECT AREA INTEREST(2)
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SOUTH TEXAS
FRIO CORE AREA
Allen Dome................... 15,669 12,511 4,128 53 33.00%
Gillock...................... 23,768 19,251 4,327 70 22.50%
Blessing..................... 848 743 252 22 33.90%
Tidehaven.................... 3,433 2,487 1,436 28 57.75%
El Maton..................... 4,085 3,443 2,219 29 64.40%
Midfield..................... 2,028 1,308 818 21 62.50%
Markham...................... 1,857 1,857 731 5 39.00%
Buckeye...................... 2,202 1,740 696 40 45.00%
Duncan Slough................ 3,644 1,940 796 25 40.90%
Southwest Pheasant........... 1,400 1,142 857 10 75.00%
Geronimo..................... 7,318 7,239 3,040 76 42.00%
Houston Endowment............ 1,116 1,116 469 50 42.00%
Wolf Point................... 632 632 287 8 45.50%
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Piledriver................... 640 640 400 2 62.50%
Archie....................... 903 826 150 14 18.13%
Powerhorn/Matagorda Bay...... 1,707 1,707 276 30 15.00%
Raymondville................. 12,139 11,598 7,003 62 60.38%
------------ ------------- ------------ --------------------
Frio Sub-Total 83,389 70,180 27,885 545
WILCOX CORE AREA
Hall Ranch(3)................ 8,310 8,285 3,438 57 41.50%
Hordes Creek(3).............. 4,730 4,683 1,943 25 41.50%
Mikeska(3)................... 8,185 7,828 2,974 32 38.00%
Duval/McMullen............... 1,980 1,980 1,782 10 90.00%
Verdad(3).................... 4,428 4,171 1,043 40 25.00%
Orangedale(3)................ 2,353 2,318 2,086 10 90.00%
Riverdale(3)................. 1,885 1,885 471 23 25.00%
------------ ------------- ------------ --------------------
Wilcox Sub-Total 31,871 31,150 13,737 197 25.00%
TEXAS HACKBERRY CORE AREA
Lox B 7,699 4,191 1,048 62 25.00%
West Port Acres.............. 729 651 81 21 12.50%
Big Hill/Stowell............. 1,462 1,333 444 56 33.33%
Cheek 5,499 3,736 461 48 12.35%
Lovells Lake................. 10,536 8,671 1,086 65 12.53%
West Beaumont................ 865 694 53 22.5 7.67%
------------ ------------- ------------ --------------------
Texas Hackberry Sub-Total 26,790 19,276 3,173 274.5
YEGUA CORE AREA
Papalote(4).................. 27,457 26,514 9,048 98 34.12%
Mathis....................... 13,083 12,694 5,077 40 40.00%
TBC ........................ 44,695 37,214 14,888 90 40.00%
South Louisiana Eocene(4).... 32,116 32,037 8,009 88 25.00%
------------ ------------- ------------ --------------------
Yegua Sub-Total 117,351 108,459 37,022 316
OTHER LOUISIANA
Lapeyrouse................... 3,539 2,429 1,093 35 45.00%
------------ ------------- ------------ --------------------
Louisiana Sub-Total 3,539 2,429 1,093 35
OTHER TEXAS
East Texas Pinnacle Reef(5).. TBD TBD TBD 400 TBD
------------ ------------- ------------ --------------------
Other Texas Sub-Total TBD TBD TBD 400
MISSISSIPPI
Thompson Creek............... 1,399 962 899 12 9.50%
Melvin....................... 408 260 60 64 23.00%
------------ ------------- ------------ --------------------
Mississippi Sub-Total 1,807 1,222 959 76
------------ ------------- ------------ --------------------
TOTAL ALL PROJECTS 264,747 232,716 83,869 1,843.5
============ ============= ============ ====================
</TABLE>
- -----------
(1) Project Gross acres refers to the number of acres within a project,
Project Net refers to leaseable acreage by tract, Company Net acres are
either leased or under option in which the Company owns an undivided
interest. Company Net acres were determined by multiplying the project
net acres leased or under option times the Company's working interest
therein.
(2) Each of the Exploration Projects differs in scope and character and
consists of one or more types of assets, such as 3-D seismic data,
leasehold positions, lease options, working interests in leases,
royalty interests or other mineral rights. The Company's percentage
interest in each Exploration Project (a "Project Interest") represents
the portion of the interest in the Exploration Project it shares with
its other project partners.
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Because each Exploration Project consists of a bundle of assets which
may or may not include a working interest in the project, the Company's
Project Interest simply represents the Company's proportional ownership
in the bundle of assets that constitute the Exploration Project.
Therefore, the Company's Project Interest in an Exploration Project
should not be confused with the working interest that the Company will
own when a given well is drilled. It is possible that while the Company
may own a 50.0% Project Interest, it may only be entitled to 25.0% of
the working interest involved in the Exploration Project. Each
Exploration Project represents a negotiated transaction between the
project partners. The Company's working interest may be higher or lower
than its Project Interest.
(3) Project is subject to reduction in ownership pursuant to the Seagull
Option Agreement.
(4) Proprietary 3-D seismic data is currently being shot over certain of
these areas.
(5) Consists of approximately 400 square miles of 3-D seismic data to which
Aspect has rights pursuant to a license agreement, and to which the
Company may acquire an interest pursuant to a geophysical technical
services agreement with Aspect.
EXPLORATION PROJECT AREA DESCRIPTIONS. The Company is focused on
certain core project areas along the Texas and Louisiana Gulf Coast where it has
pursued a trend strategy. Focusing on trends, as opposed to individual projects,
allows the Company the opportunity to gain and exploit regional knowledge,
develop competitive advantages and provide expansion room once concepts are
proven. The Company's four core trend areas are characterized by high reservoir
quality, an extensive knowledge base due to technical staff experience and
focus, and geophysical characteristics suitable to 3-D seismic imaging. The four
core trend areas are further described below:
FRIO CORE AREA.
In the Frio Trend, the Company has interests in 17 3-D seismic surveys
which cover approximately 550 square miles. It plans to drill approximately
twenty wells in the Frio Trend in 2000. This trend extends across the Texas Gulf
Coast from the Houston area to the border of Mexico. Esenjay has numerous
projects and prospects scattered throughout this large trend and has
significantly increased its planned capital expenditures in the trend as
compared with 1999. Its Raymondville Project in Willacy County, Texas is
included in the Frio Trend.
WILCOX CORE AREA.
In the Wilcox Trend, the Company has seven 3-D seismic surveys covering
approximately 200 square miles. It plans to drill approximately ten wells in the
Wilcox Trend in 2000. This trend extends through Texas from Louisiana to Mexico.
Production from the Wilcox ranges from the very shallow to over 16,000 feet in
depth. The Company's focus is on certain of the portions of the Wilcox Trend
generally located below 10,000 feet. These deeper portions have historically had
less total drilling and allow the Company ample room to expand its activities
should success in 2000 and beyond so warrant. It has significantly increased its
2000 capital budget (as compared to 1999) in this area which it believes to
represent exceptional upside potential. A portion of the Company's interests in
the Wilcox Trend are subject to the Seagull Option Agreement pursuant to which
Seagull has the right to acquire up to 50% of certain of the Company's unproven
interests for substantial cash consideration.
TEXAS HACKBERRY CORE AREA.
The Texas Hackberry Trend, sometimes referred to as the Hackberry
Embayment, is an area in which the Company has interests in six 3-D seismic
surveys covering approximately 275 square miles. It plans to drill at least six
wells in the Hackberry Trend in 2000. Based on its experience and the experience
of certain of its affiliates, the Company believes that the portions of the
Hackberry formation in geographical proximity to the Gulf of Mexico and the
Texas/Louisiana border have proven to be an excellent area for the use of 3-D
seismic data. Historical drilling in the Hackberry Sands has exhibited a low
success rate which has been greatly altered in the Company's experience in
projects in which it has participated in the Hackberry through the use of 3-D
seismic data. The Company has drilled 13 successful wells out of 18 attempts
utilizing modern 3-D seismic data. Included in the seismic evaluation of the
Texas Hackberry Trend has been significantly use of direct hydrocarbon detection
technologies.
YEGUA CORE AREA.
In the Yegua Trend, the Company currently has interests in two 3-D
seismic surveys. In addition, it has
10
<PAGE>
three additional seismic shoots, two of which are underway and one is planned
for the year 2000. The Company will own interests in an aggregate of
approximately 400 square miles of 3-D seismic data in the trend in 2000. The
Company expects to drill approximately ten wells in the Yegua Trend in 2000.
This trend extends from Beauregard Parish, Louisiana, to San Patricio County,
Texas, and is generally characterized by structural and stratigraphically
trapped hydrocarbons which may appear on 3-D seismic data as seismic anomalies.
Although estimated drilling plans for 2000 are preliminary in that certain of
the seismic data has not yet been analyzed, the Company believes that the area
is comprised of physical characteristic such that it will be well situated for
direct hydrocarbon detection technologies.
OTHER AREAS
The Company is active in other projects which are not focused on
particular trends but which create more project specific drilling opportunities.
This includes the Lapeyrouse project in Louisiana and certain other project
areas in Texas and Mississippi. The Company expects to drill several wells in
2000 in certain of these distinct project areas.
CAEX TECHNOLOGY AND 3-D SEISMIC
The Company, either directly or through its partners, uses CAEX
technology to collect and analyze geological, geophysical, engineering,
production and other data obtained about potential gas or oil prospects. The
Company uses this technology to correlate density and sonic characteristics of
subsurface formations obtained from 2-D seismic surveys with like data from
similar properties, and uses computer programs and modeling techniques to
determine the likely geological composition of a prospect and potential
locations of hydrocarbons.
Once all available data has been analyzed to determine the areas with
the highest potential within a prospect area, the Company may conduct 3-D
seismic surveys to enhance and verify the geological interpretation of the
structure, including its location and potential size. The 3-D seismic process
produces a three-dimensional image based upon seismic data obtained from
multiple horizontal and vertical points within a geological formation. The
calculations needed to process such data are made possible by computer programs
and advanced computer hardware.
While large oil companies have used 3-D seismic and CAEX technologies
for approximately 20 years, these methods were not affordable by smaller,
independent gas and oil companies until more recently, when improved data
acquisition equipment and techniques and computer technology became available at
reduced costs. The Company began using 3-D seismic and CAEX technologies in 1992
and is using these technologies on a continuing basis. The Company believes its
use of CAEX and 3-D seismic technology may provide it with certain advantages in
the exploration process over those companies that do not use this technology.
These advantages include better delineation of the subsurface, which can reduce
exploration risks and help optimize well locations in productive reservoirs. The
Company believes these advantages can be readily validated based upon general
industry experience as well as its own results in 1999. 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. Although the Company has used the technology effectively in 1999, its
history is not extensive enough to arrive at any final 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
11
<PAGE>
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.
HEDGING ACTIVITIES AND MARKETING
The Company markets its natural gas through monthly spot sales. Because
sales made under spot sales contracts result in fluctuating revenues to the
Company depending upon the market price of gas, the Company may enter into
various hedging agreements to minimize the fluctuations and the effect of price
declines or swings. In 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. In September of 1999, the Company entered into a series
of swap agreements on additional natural gas and oil production. It hedged 5,000
MMBtu's per day of natural gas for the months of September through December 1999
at a price of $3.055 per MMBtu, it hedged 3,000 MMBtu's per day for the period
of January through March of 2000, 2,400 MMBtu's per day for the period April
through June of 2000, and 1,700 MMBtu's per day for the period of July through
September of 2000, the latter three hedges of which were all at a price of $2.68
per MMBtu.
In February of 2000, in conjunction with its financing with Deutsche
Bank, the Company restructured all existing natural gas hedges with an affiliate
of Deutsche Bank. Pursuant to these hedges, the Company now has 9,381 MMBtu/day
of net production hedged in March, 2000, 9,031 MMBtu/day hedged for the second
quarter of 2000, 8,646 MMBtu/day for the third quarter of 2000, 8,278 MMBtu/day
for the fourth quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001,
6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third
quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All hedges
are at $2.45 per MMBtu. Concurrent with the restructuring of the hedges, the
Company was relieved of any liability or rights pursuant to all previously
existing natural gas hedges.
In September of 1999, the Company entered into a "collar" hedge
arrangement on certain of its oil production. It entered into an oil hedge for a
quantity equal to 300 barrels of oil per day in the fourth quarter of 1999, 280
barrels of oil per day in the first quarter of 2000, 256 barrels of oil per day
in the second quarter of 2000,
12
<PAGE>
and 237 barrels of oil per day in the third quarter of 2000, all of which
transactions were structured with an $18.00 floor price and a $20.40 cap price.
These positions were supplemented with oil hedges for 238 barrels of oil per day
in the fourth quarter of 2000, and 175 barrels of oil per day, 168 barrels of
oil per day, 161 barrels of oil per day and 154 barrels of oil per day for the
first through fourth quarters of 2001, respectively, all of which supplemental
hedges were at $21.03 per barrel.
As a result of the above-referenced transactions, the Company has
hedged varying quantities of its natural gas and oil production through December
of 2001. First quarter 2000 hedges are estimated to approximate 68% of the
Company's natural gas and 53% of its oil production for such quarter. Future
percentages will vary.
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 1998. In 1999, purchasers accounting for more
than 10% of the Company's total revenue were Coral Energy Resources, L.P., Pan
Energy Marketing Company, Duke Energy Trading & Marketing LLC and Duke Energy
Field Services, Inc. The Company does not believe the loss of any existing
purchaser would have a material adverse effect on the Company.
The Company previously had a credit facility with Duke Energy Financial
Services, Inc., pursuant to which an ongoing agreement was established which
still allows the lender the right to gather, process, transport and market, at
competitive market rates, natural gas produced from a majority of the
Exploration Projects through December 31, 2005.
OPERATING HAZARDS AND INSURANCE
The gas and oil business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations, and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases, the occurrence of any of which could
result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, cleanup responsibilities, regulatory
investigation and penalties and suspension of operations.
The Company maintains a gas and oil lease operator insurance policy
that insures the Company against certain sudden and accidental risks associated
with drilling, completing and operating its wells. There can be no assurance
that this insurance will be adequate to cover any losses or exposure to
liability. The Company also carries comprehensive general liability policies and
an umbrella policy. The Company and its subsidiaries carry workers' compensation
insurance in all states in which they operate. The Company maintains various
bonds as required by state and federal regulatory authorities. Although the
Company believes these policies are customary in the industry, they do not
provide complete coverage against all operating risks. An uninsured or partially
insured claim, if successful and of sufficient magnitude, could have a material
adverse effect on the Company and its financial condition. If the Company
experiences significant claims or losses, the Company's insurance premiums could
be increased which may adversely affect the Company and its financial condition
or limit the ability of the Company to obtain coverage. Any difficulty in
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
13
<PAGE>
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. In addition, a
recent decision of a federal district court in Louisiana casts doubt on
traditional seismic permitting practices. In some instances the surface owner
could be deemed the owner of seismic information shot across its lands.
Recently, the Fifth Circuit Court of Appeals, by decision issued January 21,
2000, reversed and remanded this case to the Louisiana federal district court.
Until this matter is finally resolved, the Company cannot predict its effect on
the Company's seismic operations.
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.
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 to a lesser
extent the Natural Gas Policy Act of 1978 ("NGPA"). Sales of the Company's
natural gas currently are made at market prices, subject to applicable contract
provisions.
The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to gas buyers and sellers
on an open and nondiscriminatory basis. The FERC's efforts have significantly
altered the marketing and transportation of natural gas. The result of the FERC
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. Although the FERC
is increasingly employing "light-handed" regulation, regulation remains an
important factor in the natural gas industry. In 2000 FERC issued Order 637
which continues the recent trend toward market-based pricing of pipeline
transportation services in certain circumstances. 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.
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
14
<PAGE>
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.
FEDERAL LEASES. We have oil and gas leases in the Gulf of Mexico, which
were granted by the federal government and are administered by the United States
Department of the Interior Minerals Management Service (the "MMS"). For offshore
operations, lessees must obtain MMS approval of exploration, development and
production plans prior to the commencement of these operations. In addition to
permits required from other agencies (such as the Coast Guard, the Army Corps of
Engineers and the United States Environmental Protection Agency (the "EPA")),
lessees must obtain a permit from the MMS prior to the commencement of drilling.
The MMS has enacted regulations requiring offshore production facilities located
on the Outer Continental Shelf ("OCS") to meet stringent engineering,
construction and safety specifications. Similarly, the MMS has enacted other
regulations governing the plugging and abandoning of wells located offshore and
the removal of all production facilities. Lessees must also comply with detailed
MMS regulations governing the calculation of royalty payments and the valuation
of production and permitted cost deductions for that purpose. On March 15, 2000,
the MMS issued a final rule, to be effective June 1, 2000, modifying the
valuation procedures for the calculation of royalties owed for crude oil sales.
When oil production sales are not in arms-length transactions, the new royalty
calculation will base the valuation of oil production on spot market prices
instead of the posted prices that were previously utilized. The main thrust of
the new rule is to move the valuation point for royalty calculation purposes
from the wellhead to sales points located downstream without allowing deductions
for the cost of moving the oil to the downstream sales point.
With respect to any operations conducted on offshore federal leases,
liability may generally be imposed under the Outer Continental Shelf Lands Act
(the "OCSLA") for costs of clean-up and damages caused by pollution resulting
from these operations, other than damages caused by acts of war or the
negligence of third parties. To cover the various obligations of lessees on the
OCS, the MMS generally requires that lessees post substantial bonds or other
acceptable assurances that these obligations will be met. Since November 26,
1993, new levels of lease and areawide bonds have been required of lessees
taking certain actions with regard to OCS leases. Operators in the OCS waters of
the Gulf of Mexico were required to increase their areawide bonds and individual
lease bonds to $3 million and $1 million, respectively, unless the MMS allowed
exemptions or reduced amounts. The MMS also has discretionary authority to
require supplemental bonding in addition to the foregoing required bonding
amounts but this authority is only exercised on a case-by-case basis at the time
of filing an assignment of record title interest for MMS approval.
LOUISIANA LEGISLATION. The Louisiana legislature passed Act 404 in
1993, which permits a party transferring an oil field site to establish a
site-specific trust account for such oil field. If the site-specific trust
account is established in accordance with the requirements of the statute, the
party transferring the oil field site shall not thereafter be held liable by the
state for any site restoration costs or actions associated with the transferred
oil field site. The parties to a transfer may elect not to establish a
site-specific trust account, however, in the absence of such an account, the
transferring party will continue to have liability for the costs of restoration
of the site. If the parties to a transfer elect to establish a site-specific
trust account pursuant to the statute, the Louisiana Department of Natural
Resources ("DNR") requires an oil field site restoration assessment to be made
at the time of the transfer or within one year thereafter, to determine the site
restoration requirements existing at the time of transfer. Based upon the site
restoration assessment, the parties to the transfer must propose to the DNR a
funding schedule for the site-specific trust account, providing for some
contribution to the account at the time of transfer and at least quarterly
payment thereafter. If the DNR approves the establishment and funding of the
site-specific trust account, the purchaser will thereafter be the responsible
party to the state, except that the failure of a transferring party to make a
good faith disclosure of all oil field site conditions existing at the time of
the transfer will render that party liable for the costs of restoration of such
undisclosed conditions in excess of the balance of the site-specific trust fund.
OIL SALES AND TRANSPORTATION RATES. The FERC also regulates rates and
service conditions for interstate transportation of crude oil, liquids and
condensate, which can affect the amount the Company receives from the sale of
these products. Rates for such transportation are generally subject to an
indexing system under which rates may
15
<PAGE>
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 expects 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
impose liability without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to be responsible for
the release of a "hazardous substance" into the environment. These persons
include (i) the current owner and operator of a facility from which hazardous
substances are released, (ii) owners and operators of the facility at the time
the disposal of hazardous substances took place, (iii) generators of hazardous
substances who arranged for the disposal or treatment at or transportation to
such facility of hazardous substances and (iv) transporters of hazardous
substances to disposal or treatment facilities selected by them. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment, for damages to natural resources and for the costs of certain
health studies, and it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other pollutants into the
environment. Furthermore, although petroleum, including crude oil and natural
gas, is exempt from CERCLA, at least two courts have ruled that certain wastes
associated with the production of crude oil may be classified as "hazardous
substances" under CERCLA, and thus such wastes may become subject to liability
and regulation under CERCLA. Regulatory programs aimed at remediation of
environmental releases could have a similar impact on the Company.
The Resource Conservation and Recovery Act, as amended ("RCRA"),
generally does not regulate most wastes generated by the exploration and
production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil, natural gas or
geothermal energy." However, these wastes may be regulated by EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes, and waste compressor oils, may be
regulated as hazardous waste. Pipelines used to transfer oil and gas may also
generate some hazardous wastes. Although the costs of managing solid and
hazardous waste may be significant, the Company does not expect to experience
more burdensome costs than similarly situated companies involved in oil and gas
exploration and production.
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
16
<PAGE>
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 disposed 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.
The Oil Spill Prevention and Response Act. To complement OPA `90, the
State of Texas enacted the Oil Spill Prevention and Response Act ("OSPRA"). The
Texas General Land Office ("GLO") is the lead agency for carrying out the OSPRA,
and to that extent the GLO has promulgated regulations affecting anyone who owns
or operates a vessel or facility that stores or transfers oil in areas when a
spill could reach Texas coastal waters.
COMPETITION
The gas and oil industry is highly competitive in all of its phases.
The Company encounters strong competition from other gas and oil companies in
all areas of its operations, including the acquisition of exploratory and
producing properties, the permitting and conducting of seismic surveys and the
marketing of gas and oil. Many of these competitors possess greater financial,
technical and other resources than the Company. Competition for the acquisition
of producing properties is affected by the amount of funds available to the
Company, information about producing properties available to the Company and any
standards the Company establishes from time to time for the minimum projected
return on investment. Competition also may be presented by alternative fuel
sources, including heating oil and other fossil fuels. There has been increased
competition for lower risk development opportunities and for available sources
of financing. In addition, the marketing and sale of natural gas and processed
gas are competitive. Because the primary markets for natural gas liquids are
refineries, petrochemical plants and fuel distributors, prices generally are set
by or in competition with the prices for refined products in the petrochemical,
fuel and motor gasoline markets.
FACILITIES
The Company leases approximately 7,600 square feet of office space in
Houston, Texas, at an annual rent of $120,463. The lease expires in September
2001. The Company leases approximately 13,300 square feet of office
17
<PAGE>
space in Corpus Christi, Texas. The annual rent is $168,137, and the Lease
expires on June 30, 2003. The Company currently has more office space than it
needs in Corpus Christi, and has sublet a portion of its office space.
EMPLOYEES
The Company has 12 full-time employees in its Houston, Texas office,
and 28 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 and Texas. Daily
production from both operated and non-operated wells net to the Company's
interest averaged 9,290 Mcf per day and 276 Bbls of oil per day for the year
ended December 31, 1999 and 14,478 Mcf per day and 487 Bbls of oil per day for
the quarter ended December 31, 1999. These properties have provided most of the
Company's revenues to date.
DRILLING ACTIVITY
From November 1, 1997 (the effective date of the Acquisitions) through
December 31, 1998, 24 exploratory wells were drilled for the Company's account,
of which 12 were completed and 11 were dry holes. In 1999, 23 exploratory and 6
developmental wells were drilled and logged for the Company's account of which
20 were completed as of March 28, 2000, 2 were waiting on completion and/or
pipelines, and 7 were dry holes, one of which logged productive but had
completion problems and will be redrilled.
The following table sets forth certain information regarding the actual
drilling results for each of the years 1997, 1998 and 1999 as to wells drilled
in each such individual year.
<TABLE>
<CAPTION>
Exploratory Development
Wells Wells
------------------- -------------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
1997
Productive.......................................... --- --- 2 0.04
Dry...................................................6 0.32 --- ---
1998
Productive ..........................................13 3.05 --- ---
Dry..................................................11 2.10 --- ---
1999
Productive ..........................................16 2.41 6 1.46
Dry...................................................7 0.87 --- ---
</TABLE>
Through the first quarter of 2000, the Company participated in the
drilling of 7 additional exploratory wells and 3 additional development wells,
of which 1 had been completed, 2 are awaiting completion, 5 were dry holes and 2
were drilling. Dry hole costs net to the Company for the first quarter of 2000
are estimated to be less than $1 million.
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<PAGE>
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the
Company's ownership as of December 31, 1999 of productive gas and oil wells in
the areas indicated.
<TABLE>
<CAPTION>
Gas Oil
-------------------- --------------------
Gross Net Gross Net
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Texas ................................................. 36 8.68 12 1.81
Oklahoma ................................................ 4 1.03 3 .26
Louisiana ............................................... 1 .08 -- --
Kansas .................................................. 1 .10 -- --
Alabama.................................................. -- -- 1 .17
-------- -------- -------- --------
Total ............................................... 42 9.89 16 2.24
======== ======== ======== ========
</TABLE>
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the
production volumes, average prices received (net of transportation) and average
production costs associated with the Company's sale of gas and oil for the
periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1999 1998
---------------- -------------
<S> <C> <C>
Net Production:
Oil (Bbl) ........................................................ 100,559 8,878
Gas (Mcf)......................................................... 3,381,592 653,325
Gas equivalent (Mcfe)............................................. 3,984,946(1) 706,593
Average sales price:
Oil ($ per Bbl).......................................................$ 18.37(2) $ 10.92
Gas ($ per Mcf)................................................... $ 2.35(2) $ 1.95(2)
Average production expenses and taxes ($ per Mcfe)........................ $ 0.35 $ 0.52
</TABLE>
(1) The majority of the net production is attributable to the fourth quarter of
1999, during which time additional exploration discoveries commenced
production.
(2) Average sales prices include the Company's hedging instruments for oil and
gas.
LEASEHOLD ACREAGE
The following table sets forth as of December 31, 1999, the gross and
net acres of proved developed and proved undeveloped and unproven gas and oil
leases which the Company holds or has the right to acquire.
<TABLE>
<CAPTION>
PROVED DEVELOPED PROVED UNDEVELOPED UNPROVEN
---------------- ------------------- -----------------
STATE GROSS NET GROSS NET GROSS NET
----- ----- --- ------- ------ ------- ---
<S> <C> <C> <C> <C> <C> <C>
Alabama......................................... 82 19 --- --- 113 22
Arkansas ....................................... --- --- --- --- 6,360 2,544
Kansas ......................................... 640 31 --- --- --- ---
Louisiana ...................................... 225 17 --- --- 44,666 12,850
Mississippi..................................... --- --- --- --- 1,807 934
Oklahoma ....................................... 2,198 51 --- --- 12,909 3,727
Texas .......................................... 8,254 2,004 203 26 183,278 61,608
------ ------ -------- ------ ------- ------
Total .................................. 11,399 2,122 203 26 249,133 81,685
====== ====== ======== ====== ======= ======
</TABLE>
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<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 Deutsche Bank AG, New York Branch a
mortgage or a right to file a mortgage on virtually all remaining gas and oil
properties to secure repayment of its credit facility with the bank.
ITEM 3. LEGAL PROCEEDINGS
The Company currently has no action filed against it other than
ordinary routine litigation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no such matters submitted in the fourth quarter of 1999.
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<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. There have been no
reported trades of the Series B Warrants since that time. The Series B Warrants
are exercisable for $12.15 per share of common stock of the Company, and expire
on the earlier of August 8, 2001 or such time as the stock trades over $24.30
for twenty consecutive days.
On September 23, 1999, the Company acquired 3DX Technologies Inc. via
merger. The price of the acquisition was approximately $7.4 million, of which
$6.7 million was in the Company's common stock and $0.7 million was in the
Company preferred stock. As a result, Esenjay issued 356,999 shares of new
convertible preferred stock which may be redeemed at Esenjay's sole option until
September 23, 2000 at $1.925 per share. If not redeemed by that time, the
preferred stock will automatically convert into one share of Esenjay common
stock on October 1, 2000 if the average closing price of Esenjay common stock is
greater than or equal to $1.875 during the month of September 2000. If the
Esenjay common stock averages less than $1.875 in September of 2000, the
preferred holder has the right, during the month of October 2000, to "put" the
shares to Esenjay. If "put", Esenjay will then have the obligation, at its
option, to either retire the convertible preferred stock for $1.65 in cash or
for shares of Esenjay common stock, with the number of shares of common stock
adjusted based upon a formula set out in the merger agreement. The new
convertible preferred stock is currently listed on the over-the-counter bulletin
board under the symbol "ESNJP". There were no 1999 trades reported in this
series of preferred stock in 1999.
The Company's common stock trades on the NASDAQ Small Cap Market under
the symbol "ESNJ". The Company estimates there are approximately 146 common
shareholders of record and 2,666 beneficial owners of the common stock. The
Series A Warrants expired in November 1998. There were no 1998 trades reported
prior to their expiration.
<TABLE>
<CAPTION>
Convertible Series B
Common Preferred(1) Warrants(2)
--------------------- ------------------- -------------------
Quarter Ended High Low High Low High Low
------------------------- --------- -------- --------- ------ ---------- ------
<S> <C> <C> <C> <C> <C> <C>
December 31, 1999 $ 2 3/8 $ 1 7/16 -- -- -- --
September 30, 1999 2 5/8 1 3/4 -- -- -- --
June 30, 1999 2 11/16 1 1/8 -- -- -- --
March 31, 1999 2 7/8 1 -- -- -- --
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
</TABLE>
(1) The Convertible Preferred Stock was redeemed in June of 1998.
(2) The Series B Warrants ceased to be listed on the NASDAQ Small Cap
Market in February of 1999. Trades in the chart through February 1999
reflect trades on the NASDAQ Small Cap Market, with no known trades
thereafter.
21
<PAGE>
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, 1999 and 1998 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 DECEMBER 31,
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 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 transactions
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.
22
<PAGE>
On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering the
Company had 15,762,723 shares outstanding.
On Exploration Projects acquired in 1998 pursuant to the Acquisitions,
the Company participated in the drilling of twenty-four wells through December
31, 1998 with working interests, which range from 8% to 79%. Out of those
twenty-four wells drilled, thirteen wells have been completed and eleven were
dry holes. Several of the successful wells went into production late in the
third quarter of 1998, and in the fourth quarter of 1998.
OVERVIEW OF 1999 ACTIVITIES. As a result of the above-described
acquisitions, restructuring, and the underwritten offering, the Company believed
it was, and believes it continues to be, positioned for a period of significant
exploration activity on its technology enhanced projects. Many of the projects
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, required several
years and the investment of significant capital. Management believes the
acquisition of projects at this advanced stage has not only reduced the drilling
risk, but should allow the Company to consistently drill on a broad array of
exploration prospects in 1999 and subsequent years.
In the first half of 1999, the Company completed a review of each of
its operating departments in order to identify areas where it could increase
efficiency and/or reduce costs. As a result, it has implemented personnel and
procedural changes in the accounting, land and operations departments. These
changes increased certain third quarter costs due to consultants fees,
employment severance packages, and new systems implementation. However, as a
result, the Company expects to achieve increased cost efficiency in certain
general, administrative, management and operational areas.
In 1999, the Company participated in 29 new wells which reached total
depth and were logged during the year. Of the total wells drilled and logged in
1999, 20 were producing as of March 28, 2000, 2 are scheduled to commence
production upon completion and pipeline connections, 7 were dry holes, 1 of
which logged productive but had mechanical completion problems and will be
redrilled. Only 2 of the 1999 wells were producing as of July 1, 1999, and as a
result the Company's net daily oil and gas production increased substantially
throughout the third and fourth quarters. Based upon estimated sustainable flow
rates, the 1999 wells helped to increase the Company's net daily production to
approximately 532 barrels of oil per day and 14,605 million cubic feet of
natural gas per day as of December 1999.
The Company's net cost in the 29 wells was approximately $8,652,439 for
drilling and completion, not including certain prior expenditures incurred at
the project level for land and seismic. It should be noted that the Company
defines a "project" as a distinct 3-D seismic data area which often comprises
several distinct exploratory "prospects". Net reserves attributable to the 29
wells drilled in 1999 total 18,466,712 MCFE including 1999 production and
December 31, 1999 remaining reserves. On a present value basis, the Company
achieved a present value in excess of four times the 1999 drilling and
completion costs expended.
The Company ended 1999 having gone from nominal third quarter 1998 gas
and oil revenues of approximately $35,000 per month and large operating cash
flow deficits to a company which averaged $1,815,637 per month in net oil and
gas revenues and associated hedging revenues from commodity transactions in the
fourth quarter of 1999. This number increased significantly as the wells drilled
in 1999 continued to come on line. This allowed the Company to achieve positive
operating cash flow (before capital expenditures, and before the costs of
acquisition of new 3-D seismic data, and changes in working capital) in the
third quarter, which operating cash flow increased in the fourth quarter. As a
result of this trend, approximately 56% of the Company's 1999 gas and oil
revenue was attributable to the fourth quarter of the year.
On May 12, 1999, the Company announced that it had entered into a Plan
and Agreement of Merger with 3DX Technologies, Inc. ("3DX") which provided for
the merger of 3DX into the Company. The shareholders of both companies approved
the transaction at their respective meetings on September 23, 1999 and the
merger was consummated the same day. The terms of the merger provided for 3DX
shareholders to receive, at their election, either (i) the issuance of one share
of Esenjay common stock for 3.25 shares of 3DX common stock; or (ii) the
issuance of a new Esenjay convertible preferred stock at a ratio of one share of
Esenjay convertible preferred stock for each 2.75
23
<PAGE>
shares of 3DX common stock. The preferred stock does not require payment of
dividends. Approximately 91% of the 3DX common shares converted into Esenjay
common stock and approximately 9% were converted into Esenjay convertible
preferred stock. As a result, Esenjay issued approximately 2,906,800 new shares
of common stock and approximately 357,000 shares of convertible preferred stock.
The convertible preferred stock may be redeemed at Esenjay's sole
option until September 23, 2000 at $1.925 per share. If not redeemed by that
time, the preferred will automatically convert into one share of Esenjay common
stock on October 1, 2000 if the average closing price of Esenjay common stock is
greater than or equal to $1.875 during the month of September 2000. If the
Esenjay common stock averages less than $1.875 in September of 2000, the
preferred holder has the right, during the month of October of 2000, to "put"
the shares to Esenjay. If put, Esenjay will then have the right to retire the
convertible preferred stock for $1.65 in cash or for common stock with the
number of shares of common stock adjusted based upon a formula set out in the
merger agreement. The convertible preferred stock is scheduled to be converted
or redeemed not later than November 1, 2000.
OVERVIEW OF 2000 ACTIVITIES. The Company believes it enters 2000 in a
position to continue to expand its exploration activities on its
technology-enhanced projects. By utilizing its increased capital available to it
from cash flow, financings and industry partner transactions, the Company
intends to pursue an aggressive exploration budget in all of its major trends of
activity. The Company's net daily production approximated 530 barrels of oil per
day and 13,767 Mcf natural gas per day in March of 2000. This net production is
after a reduction of 6 barrels of oil per day and 1,981 Mcf of natural gas per
day attributable to the sale of interests in the Raymondville Project as
described below in this paragraph. The Company has also successfully improved
its working capital and cash resources. On February 7, 2000, it announced the
closure of a $29 million credit facility with Deutsche Bank AG, New York Branch.
Initial availability pursuant to the facility was $21 million with a borrowing
base adjustment scheduled for the second quarter of 2000. A portion of the
available proceeds was utilized to retire approximately $15.8 million of
previously existing debt with Bank of America and Duke Energy Financial
Services, Inc., of which approximately $11 million was classified as the current
portion of long-term debt. The amount outstanding under the new facility was all
classified as long term debt. In addition, the Company sold approximately 84.39%
of its interest in its Raymondville Project in Willacy County to Cody Texas,
L.P. for cash proceeds of $10,940,000 ($10,585,981 net of transaction fees). The
sale closed on March 20, 2000 but was effective as of January 1, 2000. Pursuant
to this sale the Company sold 3,462,967 MCFE of its reserves classified as
proven as of December 31, 1999. Its borrowing base availability with Deutsche
Bank was not reduced. The combination of these two financing transactions
provided $15.8 million in net additional cash resources (after repayment of
existing debt) and created significant positive working capital for the Company.
As a result of its current cash flow and the impact of these two transactions,
the Company believes it is well positioned to fund its 2000 drilling activities,
the results of which are intended to help continue the upward trends of
increasing cash flow and reserves. The Company will look to a variety of sources
to further supplement its capital expenditures budget, including its credit
facilities and sales of additional promoted project interests to industry
partners, as it seeks to maximize its interests and manage its risks while
aggressively pursuing its exploration projects.
The Company has budgeted $18,000,000 in drilling and completion
expenditures on interests in over 40 wells and an additional $8,000,000 in land
and new seismic costs in 2000. The budgeted drilling and completion
expenditures, which are primarily on exploratory wells, compares to total
drilling and completion expenditures of approximately $8,652,439 in 1999 when
the Company had less capital available. Through this exploration program, the
Company believes it can continue its 1999 trends of rapid growth in net
production, net revenues, operating cash flow, and net gas and oil reserves
throughout the year 2000 and beyond. It believes that certain of its planned
2000 exploratory wells represent the highest upside potential to which the
Company has been exposed.
As of March 27, 2000, the Company has approximately 18,770,000 total
shares of common stock and 357,000 total shares of preferred stock outstanding.
It employs 40 full time employees, including 12 in its geological and
geophysical departments, 7 in its operations department, and 11 in its land
department. Its focus continues to be the implementation of its business
strategy as set forth in this section.
SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes
the successful efforts method of accounting. Under this method it expenses its
exploratory dry hole costs and the field acquisition costs of 3-D seismic data
as incurred. The undeveloped properties, which were acquired pursuant to the
Acquisitions, were comprised primarily of interests in unproven 3-D seismic
based projects, and were recorded in May of 1998 at an independently estimated
fair market value of $54.2 million as determined by Cornerstone Ventures, L.P.,
a Houston,
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Texas based investment banking firm. Pursuant to the successful efforts method
of accounting, the Company is amortizing such initial costs of unproved
properties on a straight-line basis over a period not to exceed forty-eight
months, as well as recognizing property specific impairments. As of December 31,
1999 the unamortized balance was $13,448,700. Hence significant non-cash charges
have depressed reported earnings of the Company and will likely continue to do
so in 2000; however, the non-cash charges will not affect cash flows provided by
operating activities nor the ultimate realized value of the Company's natural
gas and oil properties.
As a result of the tax rules applicable to the Acquisitions, the
Company will likely not be able to fully use its existing net operating loss
carry forward in the future.
YEAR 2000
The Company's efforts with respect to the Year 2000 issue were handled
internally by management and other Company personnel. Costs of developing and
carrying out this initiative were funded from the Company's operations and did
not represent a material expense to the Company. The Company has not encountered
any significant problems in this regard and believes that it will not in the
future. As a result, the costs of addressing the Year 2000 issue were not
significant and did not have a material adverse impact on the Company's
financial condition.
COMPARISON OF 1999 TO 1998.
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, information regarding dates prior to May 14, 1998 is of
limited value.
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,
--------------------------------------
1999 1998
----------------- -----------------
<S> <C> <C>
Net Production:
Oil (Bbl) ................................................ 100,559 8,878
Gas (Mcf) ................................................ 3,381,592 653,325
Gas equivalent (Mcfe) .................................... 3,984,946(1) 706,593
Average sales price:
Oil ($ per Bbl)........................................... $ 18.37(2) $ 10.92
Gas ($ per Mcf) .......................................... $ 2.35(2) $ 1.95(2)
Average production expenses and taxes ($ per Mcfe)................. $ 0.35 $ 0.52
</TABLE>
(1) The majority of the net production is attributable to the fourth quarter of
1999, during which time additional exploration discoveries commenced
production.
(2) Average sales prices include the Company's hedging instruments for oil and
gas.
REVENUES. Total revenues increased 632% from $1,716,473 for the year
ended December 31, 1998 to $12,566,165 for the year ended December 31, 1999.
This is primarily attributable to the significant increases in the Company's net
gas and oil production in the second half of 1999 and, to a lesser extent,
increases in the gain or sale of assets.
GAS AND OIL REVENUES. Total gas and oil revenues increased 612.93% from
$1,372,002 to $9,781,352. The increase in gas and oil revenue was attributed
mainly to revenues from wells placed into production during the third and fourth
quarters of 1999. In addition increases in oil and gas prices in the second half
of 1999 compared to the same period one year previous, contributed to the
increase in revenues.
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GAIN ON SALE OF ASSETS. There was an increase in gain on sale of assets
of $2,238,136 from $5,375 reported in 1998 to $2,243,511 reported in 1999. This
primarily related to the sale of promoted interests to industry partners.
OPERATING FEES. Operating fees increased due to increases of both
exploratory and developmental wells operated, which has resulted in the increase
of operating fees of 22.17% from $282,020 for the year ended 1998 to $344,539
for the year ended 1999.
REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. The Company realized
losses from various commodity hedges of $113,911 for the year ending 1998, and
realized a gain of $146,337 for the same period in 1999. The losses realized
during 1998 were attributed to various transactions in which the Company hedged
future gas delivery obligations as a requirement of its bank loan facility. The
gains realized during 1999 were attributed to the Company's average hedge
pricing exceeding the spot market prices for the period.
UNREALIZED GAIN ON COMMODITY TRANSACTIONS. The Company recognized an
unrealized gain on commodity transactions in 1998 of $128,936, as compared to
none during 1999. This was due to 1999 oil and gas production volumes exceeding
those volumes hedged. Unrealized gain or loss is not recognized when production
volumes are in excess of hedged volumes, as was the case in 1999.
OTHER REVENUES. The Company had other revenues of $42,051 for the year
of 1998 as compared with $50,426 for the year of 1999.
COSTS AND EXPENSES. Total costs and expenses decreased 26.49% from
$31,037,820 in 1998 to $22,816,403 in 1999. The most significant decreases were
in Impairment of Oil and Gas Properties and in Exploration Costs Geological and
Geophysical and in Exploration Costs - Dry Hole. These cost decreases were
partially offset by increases in lease operating expenses, production taxes,
depletion, depreciation and amortization, and general and administrative
expenses.
AMORTIZATION OF UNPROVED PROPERTIES was $7,546,000 for 1999 and
$6,937,300 in 1998. The Company is amortizing the undeveloped and unevaluated
value of the properties acquired pursuant to the Acquisition Agreement between
the Company, EPC and Aspect over a period not to exceed forty-eight months. The
amounts are amortized until the applicable properties are moved into the proven
property base or reduced to zero by amortization or impairment. As of December
31, 1999, a $13,392,100 balance remained in this amortization pool. Also see
Overview - Successful Efforts Accounting and Related Matters.
IMPAIRMENT OF GAS AND OIL PROPERTIES was $5,832,024 in 1998 compared to
$358,106 in 1999. Management periodically reviews each individual Exploration
Project which can result in the decision to expense the book value of certain
projects based upon the belief that they no longer have a realistic potential to
realize the book value from such projects in the future. Major impairment
realized in 1998 contrasted with modest impairments in 1999.
EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL decreased 72.84% from
$5,882,307 for 1998 to $1,597,372 for 1999. These exploration costs reflect the
costs of topographical, geological and geophysical studies and include the
expenses of geologists, geophysical crews and other costs of acquiring and
analyzing 3-D seismic data. The Company's technology-enhanced exploration
program on the Exploration Projects required the historical acquisition and
interpretation of substantial quantities of such data. In 1999, most of the
Company's projects had reached the drilling stage and these costs have decreased
for 1999 as compared with 1998. The Company considers 3-D seismic data a
valuable asset; however, its successful efforts accounting method requires such
costs to be expensed for accounting purposes. The cash flow statement does not
permit expenditures for geological and geophysical costs to be included as an
oil and gas investing activity or as an add back to operating activities. The
cash flow from/(used in) operating activities would be $1,052,088 and $5,750,979
for 1999 and 1998, respectively, if the geological and geophysical add back was
permitted. The cash flow used in investing activities would be $6,665,047 and
$24,927,722 for 1999 and 1998, respectively, if the geological and geophysical
cost were permitted to be included.
EXPLORATION COSTS - DRY HOLE was $5,213,930 for 1998 compared to
$692,642 for 1999. This decrease was the result of several factors. The Company
drilled a higher percentage of successful wells. It also reduced risk taken by
the Company through carried and partially carried interests in drilling wells
where the majority of the risk
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<PAGE>
was assumed by other participants in those wells. In addition, the Company's
sale of a portion of its interest also reduced these costs. During 1999, the
Company participated in the drilling of 29 wells of which 6 were dry holes that
were expensed.
GENERAL AND ADMINISTRATIVE EXPENSES increased 26.92% from $4,501,656
for 1998 as compared to $5,713,408 for 1999. This increase was primarily due to
an increase in operational expenses incurred after May 14, 1998, the effective
date of the Acquisition Agreement with Aspect and EPC, and the acquisition of
3DX in September of 1999. As a result, the increased expenses affected only
eight months in 1998 and twelve months in 1999. In addition, approximately
$566,385 in general and administrative costs for 1999 were costs associated with
departmental reorganizations and information system conversions and
implementation.
DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 181.91%
from $1,522,771 for 1998 to $4,292,837 in 1999. The increase was primarily
attributed to increased gas and oil production from wells placed into production
during 1999.
INTEREST EXPENSE increased 40.54% from $620,121 for 1998 to $871,501
for 1999. The increase in interest expense was primarily attributable to the
credit facility with Duke Energy Financial Services, Inc., which closed in
February of 1999, and an increase in the borrowing base pursuant to the
Company's credit facility with Bank of America, NT&SA in October 1998. The
Company capitalized a large portion of its interest associated with ongoing
projects, of which capitalized amounts totaled $456,901 and $1,023,221 for the
respective years ending 1998 and 1999.
PRODUCTION TAXES increased 584.38% from $95,728 for 1998 to $655,145
for 1999. The increase in production taxes was primarily attributed to revenues
of wells placed in production during the third and fourth quarters of 1999, and
revenues obtained by the Company from the 3DX merger which closed on September
23, 1999.
LEASE OPERATING EXPENSE increased 176.18% from $272,600 for 1998 to
$752,861 for 1999. This increase is largely attributable to the addition of
wells drilled, completed and placed into production in 1999. In addition, the
increase in oil and gas prices the second half of 1999 justified remedial work
on certain marginal wells, primarily non-operated, which work was performed
during 1999. The addition of producing wells acquired through the 3DX merger
also contributed to this increase.
DELAY RENTAL EXPENSE increased 111.15% from $159,383 for 1998 to
$336,531 for 1999. This increase is primarily attributable to rentals payable on
leases acquired for projects and prospects not yet developed but were determined
to be a part of the Company's proved undeveloped reserves. In addition, many of
the rentals were also due on leases that were part of the wells drilled in 1999
and are scheduled to be drilled in 2000.
NET LOSS PER COMMON SHARE. Net loss per common share decreased from a
net loss of $2.97 per share for 1998 to a net loss of $0.62 per share for 1999.
Due to factors discussed above, there was a decrease in net loss applicable to
common stockholders of $19,119,245 from 1998 as compared to 1999 combined with
the increase of weighted average number of common equivalent shares at December
31, 1999, resulting from the merger 3DX. Approximately 16,612,000 weighted
average common equivalent shares were outstanding at December 31, 1999 as
compared with approximately 9,882,000 at December 31, 1998.
KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE
OPERATING RESULTS.
The Company's future operating results will continue to be
substantially dependent upon the success of the Company's efforts to develop the
projects acquired in the Acquisitions and the acquisition of 3DX, as well as its
other prospects.
Management continues to believe these projects represent the most
promising prospects in the Company's history. The wells drilled in 1998 and 1999
on projects acquired pursuant to the Acquisitions continue to substantially
increase the Company's revenues. Conversely, the capital expenditures planned in
2000 will continue to require substantial outlays of capital to explore, develop
and produce. Drilling results for 1998 resulted in substantial revenue
increases. Drilling results in 1999 resulted in rapidly expanding revenues in
the third and fourth
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<PAGE>
quarters of 1999. The Company anticipates certain general and administrative
cost decreases in 2000 due to personnel and systems changes which have been
implemented, which are intended to increase efficiency and/or reduce costs.
However, pursuant to the acquisition of 3DX Technologies, Inc., certain of the
planned savings have been offset by staff additions pursuant to the merger. Such
cost additions should be more than offset by revenue increases from producing
properties acquired in the merger and the additions expand the Company's ability
to manage and create value from its broad project inventory. However, because of
the Company's expanded 2000 drilling budget, capital from sources other than
cash flow from operations is required for funding planned exploration
activities. The recently closed Raymondville Interests Sale has, however,
provided the cash resources to substantially fund the 2000 capital budget when
combined with available credit facilities and anticipated operating cash flow.
The Company's 2000 budget will, however, continue to include the sales of
certain project interests to industry partners; however, the Company believes it
will be much less dependent upon such sources due to its increasing operating
cash flow, improved liquidity, and new credit facility.
LIQUIDITY AND CAPITAL RESOURCES
The Company business plan calls for net expenditures of $18,000,000 in
drilling and completion and $8,000,000 in land and geophysical costs resulting
in a $26,000,000 capital budget for 2000. These budgeted amounts are based upon
exploration opportunities and may be adjusted based upon available capital, new
opportunities and industry conditions. The Company's sources of financing
include borrowing capacity under its credit facilities, the sale of promoted
interests in the Exploration Projects to industry partners and cash provided
from operations. The Company's budget includes the sales of certain project
interests to industry partners.
The Company entered 1999 having gone from nominal second quarter 1998
gas and oil production revenues of approximately $35,000 per month and large
operating cash flow deficits to a company which averaged $1,815,637 per month in
oil and gas revenues and in realized revenue from hedges on production in the
fourth quarter of 1999. Gas and oil production is expected to continue to
increase as new gas and oil production from wells drilled in 1999 and 2000
continues to come on line. Based upon estimated sustainable flow rates, new
wells increased the Company's net daily production to approximately 532 barrels
of oil per day and 14,602 Mcf of natural gas per day as of December 31, 1999.
These rates are approximately 530 net barrels of oil per day and 13,767 net Mcf
of natural gas per day in March of 2000, after giving effect to the Raymondville
Interests Sale effective January 1, 2000, which sale included 6 net barrels of
oil and 1,981 net Mcf of natural gas per day. Additional success in 2000 on
wells currently drilling would continue the trend of increasing production. This
should allow the Company to achieve steadily increasing operating cash flow
(prior to capital expenditures and new 3-D seismic data acquisition costs, which
costs the successful efforts accounting method utilized by the Company mandate
to be expensed rather than capitalized).
The Company ended 1999 with a deficit working capital of approximately
$16,543,374. Of this amount approximately $11.0 million was represented by the
current portion of its long term debt. This deficit working capital was greatly
improved when the Company, on January 25, 2000, closed a new credit facility
with Deutsche Bank AG, New York Branch. Pursuant to this facility, all of the
$15.8 million of the Company's long term debt at December 31, 1999 was repaid.
This repayment included $4.8 million of long term debt classified as long term
and the approximate $11.0 of long term debt classified as current portion.
Pursuant to the Deutsche Bank credit facility, $21 million was initially
available. All amounts available were long term debt, none of which would have
been classified as current portion in the first quarter of 2000. The credit
facility with Deutsche Bank is in two tranches. $12 million was available under
Tranche A, and $9 million under Tranche B. Tranche A is a revolving facility
with no required principle payments until January 24, 2001, after which date it
converts into a 60-month term loan. Tranche B is payable interest only until the
second quarter of 2001, at which time the principle is amortized at a rate of
25% per quarter until fully repaid. Both loans are at a varied interest rate
utilizing either Deutsche Bank's alternative interest rate or the London
interbank rate plus 2% for both Tranche A and Tranche B. As of the January 25,
2000 closing date, $8,341,782 was drawn under Tranche A and $9 million under
Tranche B. All undrawn funds will be available for future drilling activities of
the Company. The facility is secured by a mortgage on most proven properties
currently owned by the Company. In addition, the Company has a negative pledge
and an agreement to mortgage any of the Company's unproven projects or
properties at the demand of the bank. In addition to the foregoing, Deutsche
Bank AG received a 1.5% overriding royalty interest, proportionately reduced to
the Company's net interest, on the gas and oil properties classified as proven
as of the date of closing, and an agreement
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<PAGE>
that it would convey to the bank a 1.5% overriding royalty interest,
proportionately reduced to the Company's net interest on future proven wells on
the date any such future wells are logged, for as long as funds are outstanding
pursuant to Tranche B. In the event the Tranche B loans are repaid in full prior
to April 30, 2002, the Company may redeem the overriding royalty interests
conveyed to Deutsche Bank AG for an amount equal to (a) an amount which, when
added to the interest paid to Deutsche Bank AG, plus revenues received by
Deutsche Bank AG from the overriding royalties conveyed to Deutsche Bank AG,
would provide to Deutsche Bank AG an internal rate of return of approximately
15%, plus (b) 60% of the then remaining present value of the overriding
royalties to be redeemed after subtracting the amount calculated in (a) above.
In addition, Deutsche Bank also received a five-year warrant to purchase 250,000
shares of the Company's common stock at a price equal to $1.50 per share.
Proceeds of the credit facility were utilized to retire the Company's existing
long term debt and additional proceeds can be utilized to supplement working
capital and exploration costs. The Company expects further increases in the
borrowing base in the event its proven oil and gas reserves continue to grow.
The Company's working capital was further enhanced when it closed a
sale of project interests to Cody Texas, L.P. for an amount net to the Company
totaling approximately $10,585,591 on March 17, 2000. In this sale, the Company
conveyed 84.39% of its net interest in its Raymondville Project in Willacy
County, Texas to Cody Texas, L.P. The Company's borrowing base pursuant to
Tranche A with Deutsche Bank was not reduced as a result of the sale. The
proceeds of the sale of interests to Cody Texas, L.P. will be utilized to
increase working capital, and to reduce outstandings under the revolving
borrowing base available to the Company pursuant to Tranche A of the Deutsche
Bank facility, and to fund capital expenditures of the Company.
The Company believes that it has achieved a much more desirable
position from a standpoint of liquidity than it has experienced since the
consummation of the Acquisitions in May of 1998. Improvements to its working
capital position which have resulted from the closing of the facility with
Deutsche Bank and the sale to Cody Texas, L.P., combine with the Company's
recently rapidly increasing cash flow to place it in a good position to fund its
year 2000 capital expenditures budget. Said budget is, in fact, substantially
funded from cash, currently available credit and anticipated operating cash
flow. Given the $26 million budget, the Company anticipates that the full
funding of said budget may still depend upon some sales or other transactions
with industry partners in the second half of the year 2000. Its ongoing business
plan is to always implement such transactions in order to properly manage the
spread of risk in its drilling activities as well as to be a source of capital
expenditure funds.
Pursuant to the Company's credit agreement with Deutsche Bank, it has
certain covenants regarding current interest coverage ratios and other covenants
regarding which it is expected to be in compliance at the end of each quarter.
Although the Company believes it can be in compliance with these covenants in
the year 2000, there can be no assurance that it will be in compliance. In the
event it is not in compliance, the Company will be required to seek waivers of
said covenants or would be required to seek alternative financing arrangements.
The Company historically has addressed its long-term liquidity needs
through the issuance of debt and equity securities, through bank credit and
other credit facilities, sales of project interests to industry partners and
with cash provided by operating activities. Its major obligations as of March
2000, consisted principally of (i) servicing loans under the credit facilities
with Deutsche Bank and other loans, (ii) funding of the Company's exploration
activities, and (iii) funding of the day-to-day operating costs.
The Company has an ambitious capital expenditure plan for 2000, which
includes approximately $18,000,000 in drilling and completion costs, and an
additional $4,600,000 and $3,600,000, respectively, in geological, geophysical
and land costs for the year. Cash on hand, cash currently available pursuant to
the Deutsche Bank credit facility, and cash flow from operations will contribute
significantly to said budgets, but additional funds in the form of sales of
project interests and/or long term debt will likely be needed in the second half
of the year.
Many of the factors that may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control, including,
but not limited to, oil and natural gas prices, governmental actions and taxes,
the availability and attractiveness of financing and its operational results.
The Company continues to examine alternative sources of long-term capital,
including the acquisition of a company with producing properties for common
stock or other equity securities, and also including bank borrowings, the
issuance of debt instruments, the
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<PAGE>
sale of common stock or other equity securities, the issuance of net profits
interests, sales of promoted interests in its Exploration Projects, and various
forms of joint venture financing. In addition, the prices the Company receives
for its future oil and natural gas production and the level of the Company's
production will have a significant impact on future operating cash flows.
In order to minimize the pricing risk associated with oil and gas
sales, and as required pursuant to its Deutsche Bank credit facility, the
Company has entered into hedging transactions with Deutsche Bank AG.
The Company markets its natural gas through monthly spot sales. Because
sales made under spot sales contracts result in fluctuating revenues to the
Company depending upon the market price of gas, the Company may enter into
various hedging agreements to minimize the fluctuations and the effect of price
declines or swings. In February of 2000, in conjunction with its financing with
Deutsche Bank, the Company restructured all existing natural gas hedges with an
affiliate of Deutsche Bank. Pursuant to these hedges, the Company now has 9,381
MMBtu/day of net production hedged in March, 2000, 9,031 MMBtu/day hedged for
the second quarter of 2000, 8,646 MMBtu/day for the third quarter of 2000, 8,278
MMBtu/day for the fourth quarter of 2000, 7,161 MMBtu/day for the first quarter
of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the
third quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All
hedges are at $2.45 per MMBtu. Concurrent with the new hedges, all prior natural
gas hedges were retired. In September of 1999, the Company entered into a
"collar" hedge arrangement on certain of its oil production. It entered into an
oil hedge for a quantity equal to 300 barrels of oil per day in the fourth
quarter of 1999, 280 barrels of oil per day in the first quarter of 2000, 256
barrels of oil per day in the second quarter of 2000, and 237 barrels of oil per
day in the third quarter of 2000, all of which transactions were structured with
an $18.00 floor price and a $20.40 cap price. These positions were supplemented
with oil hedges for 238 barrels of oil per day in the fourth quarter of 2000,
and 175 barrels of oil per day, 168 barrels of oil per day, 161 barrels of oil
per day and 154 barrels of oil per day for the first through fourth quarters of
2001, respectively, all of which supplemental hedges were at $21.03 per barrel.
As a result of the above-referenced transactions, the Company has hedged varying
quantities of its natural gas and oil production through December of 2001. First
quarter 2000 hedges are estimated to approximate 68% of the Company's natural
gas and 53% of its oil production for such quarter. Future percentages will
vary.
WORKING CAPITAL. At December 31, 1999, the Company had a cash balance
of $2,598,047, total current assets of $13,979,316, and total current
liabilities of $30,522,690. This resulted in a working capital deficit of
$16,543,374. The largest component of the working capital deficit was the
current portion of long term debt which totaled $11,013,162, which was due in
varying amounts from the time frame February through August of 2000. Pursuant to
the closing of the Deutsche Bank credit facility, all of which is classified as
long term debt in March of 2000, all long term debt totaling $15,763,162 on
December 31, 1999, including the current portion of long-term debt of
$11,013,162, was retired. Had said debt been retired at December 31, 1999, the
working capital would have been $11,013,162 higher, and additional increases to
working capital due to the availability of additional long term debt which was
not drawn would have been available. The Company's cash position was also
enhanced in March of 2000 by its previously referenced Raymondville Interest
Sale pursuant to which the Company conveyed 84.39% of its interest in its
Raymondville Project for a net cash consideration, after transaction costs, of
$10,585,591. The Company expects its trend of increasing gas and oil revenues
and associated hedging revenues from commodity transactions will continue the
growth in revenues in excess of the ongoing costs of operations, which may also
enhance the Company's working capital position. The net working capital can be
negatively effected by the Company's continuing aggressive capital expenditures
program on its exploration projects to the extent said capital expenditures
exceed cash generated from operations and from the sale of project interests
and/or growth in its credit facilities.
SUMMARY. The Company believes it is positioned to continue to expand
its exploration activity on its technology enhanced projects. Many of the
projects have reached the drilling stage. In 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 2000.
As evidence of this activity the Company has participated in the
drilling of 29 wells on its exploration projects
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in 1999. Of the total wells drilled in 1999, 20 were drilled and successfully
completed, 2 are scheduled to commence production upon pipeline connections, and
7 were dry holes. One of the dry holes logged productive but had mechanical
completion problems, and it will be redrilled in 2000. The addition of wells
drilled in 1999 to producing status has increased the Company's net daily
production to approximately 530 barrels of oil per day and 13,767 Mcf of natural
gas per day as of March 15, 2000, after adjustment for the sale of interests in
the Raymondville Project in March of 2000. The Company expects that these
revenues will provide positive and growing operating cash flow in 2000 (prior to
capital expenditures and new 3-D seismic data acquisition costs, which costs the
successful efforts accounting method utilized by the Company mandates to be
expensed rather than capitalized). The Company's recent drilling results have
further served to increase its confidence in its future drilling on the
technology enhanced Exploration Projects. Additional exploration success would
continue this positive trend.
The Company expects to fund significant portions of its $18 million
year 2000 drilling and completion budget from operating cash flow (prior to
capital expenditures and new 3-D seismic data acquisition costs). Its total
capital budget, including land and new seismic, of $26 million is substantially
funded from anticipated cash flow and available credit facilities. The Company
will utilize a variety of sources to fund its continuing capital expenditures
budget including operating cash flow, currently available credit facilities and
certain sales of promoted project interests to industry partners, as it seeks to
maximize its interests and manage its risks while aggressively pursuing its
exploration projects.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In June 1999, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferred of the Effective Date
of FASB Statement No. 133" ("SFAS 137"). SFAS 137, which is effective for all
fiscal quarters of fiscal years beginning after June 15, 2000, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts (collectively referred to as
"derivatives") and for hedging activities. SFAS 137 requires that an entity
recognize all derivatives as either assets or liabilities in the balance sheet
and measure those instruments at fair value. The Company is currently evaluating
the impact of the application of SFAS 137, which when adopted, could have a
material effect on its consolidated financial statements.
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 23-month
period with Deutsche Bank AG. The hedging instruments called for the delivery of
volumes which range from 9,381 to 6,319 MMBtu per day of natural gas at a price
of $2.45 per MMBtu for the period February 2000 through December 2000. They also
call for the delivery of volumes which range from 280 to 237 barrels of oil per
day at prices which range from $18.00 to $20.40 per barrel for the period
January 2000 to September 2000, and a volume of 238 barrels of oil per day at a
hedge price of $21.03 per barrel from October through December of 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. and subsidiaries (the "Company") as of December 31, 1999 and
1998, 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, 1999 and 1998, and the results of its operations and its cash flows
for the years then ended in conformity with generally accepted accounting
principles.
Deloitte & Touche LLP
Houston, Texas
April 10, 2000
32
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1999 1998
------------------- ----------------
<S> <C> <C>
Current assets:
Cash and cash equivalents......................................... $ 2,598,047 $ 646,200
Accounts receivable, net of allowance for doubtful
accounts of $519,137 at December 31, 1999 and
$348,984 at December 31, 1998................................... 7,078,109 3,209,633
Prepaid expenses and other......................................... 3,940,133 122,422
Receivables from affiliates........................................ 363,027 963,700
------------------- ----------------
Total current assets......................................
13,979,316 4,941,955
Property and equipment.................................................. 80,120,781 70,044,882
Less accumulated depletion, depreciation
and amortization................................................... (25,937,472) (15,517,656)
------------------- ----------------
54,183,309 54,527,226
Other assets .......................................................... 770,210 447,091
------------------- ----------------
Total assets.............................................. $ 68,932,835 $ 59,916,272
=================== ================
</TABLE>
33
<PAGE>
ESENJAY EXPLORATION, INC.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1999 1998
----------------- ----------------
<S> <C> <C>
Current liabilities:
Accounts payable....................................................... $ 8,838,629 $ 8,993,859
Accounts payable to affiliate, net..................................... 2,083,913 4,322,548
Revenue distribution payable........................................... 2,491,798 1,996,091
Current portion of long-term debt...................................... 11,013,162 101,236
Accrued, deferred and other liabilities................................ 6,095,188 484,756
----------------- ----------------
Total current liabilities..................................... 30,522,690 15,898,490
Long-term debt ............................................................. 4,750,000 7,500,000
Non-recourse debt .......................................................... 864,000 864,000
Accrued interest on non-recourse debt ...................................... 463,395 331,194
----------------- ----------------
Total liabilities ............................................ 36,600,085 24,593,684
Stockholders' equity:
Convertible preferred stock $.01 par value;
5,000,000 shares authorized; 356,999 shares issued and
outstanding at December 31, 1999.................................... 3,570 ---
Common stock:
Class A common stock, $.01 par value; 40,000,000
shares authorized; and 18,837,699 and
15,784,834 outstanding at December 31, 1999
and 1998, respectively.............................................. 188,377 157,849
Additional paid-in capital ............................................ 84,877,904 77,651,602
Accumulated deficit.................................................... (52,737,101) (42,486,863)
----------------- ----------------
Total stockholders' equity.................................... 32,332,750 35,322,588
----------------- ----------------
Total liabilities and stockholders' equity.................... $68,932,835 $59,916,272
================= ================
</TABLE>
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,
-----------------------------------------
1999 1998
------------------ -----------------
<S> <C> <C>
Revenues:
Gas and oil revenues.................................................... $ 9,781,352 $ 1,372,002
Realized gain (loss) on commodity transactions.......................... 146,337 (113,911)
Unrealized gain on commodity transactions............................... --- 128,936
Gain on sale of assets.................................................. 2,243,511 5,375
Operating fees.......................................................... 344,539 282,020
Other revenues.......................................................... 50,426 42,051
------------------ -----------------
Total revenues................................................. 12,566,165 1,716,473
------------------ -----------------
Costs and expenses:
Lease operating expense................................................. 752,861 272,600
Production taxes........................................................ 655,145 95,728
Depletion, depreciation and amortization................................ 4,292,837 1,522,771
Amortization of unproved properties..................................... 7,546,000 6,937,300
Impairment of oil and gas properties.................................... 358,106 5,832,024
Exploration costs-geological & geophysical.............................. 1,597,372 5,882,307
Exploration costs-dry hole.............................................. 692,642 5,213,930
Interest expense........................................................ 871,501 620,121
Delay rentals........................................................... 336,531 159,383
General and administrative.............................................. 5,713,408 4,501,656
------------------ -----------------
Total costs and expenses....................................... 22,816,403 31,037,820
------------------ -----------------
Loss before provision for income taxes....................................... (10,250,238) (29,321,347)
Benefit (provision) for income taxes......................................... --- ---
Net loss .................................................................... (10,250,238) (29,321,347)
Cumulative preferred stock dividend.......................................... --- 48,136
------------------ -----------------
Net loss applicable to common stockholders................................... $ (10,250,238) $(29,369,483)
================== =================
Basic and diluted loss per common and common equivalent share................ $ (0.62) $ (2.97)
================== =================
Weighted average number of common shares outstanding......................... 16,612,314 9,882,227
================== =================
</TABLE>
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, 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)
Issuance of common
stock for
acquisitions, net.......... -- -- 2,906,839 29,068 -- 6,378,334 --
Issuance of
preferred stock............ 356,999 3,570 -- -- -- 683,653 --
Issuance of common
Stock..................... -- -- 62,026 620 -- 121,235 --
Issuance of common
stock through
subscriptions.............. -- -- 84,000 840 -- 152,880 --
Net loss..................... -- -- -- -- -- -- (10,250,238)
----------- ---------- ------------- ----------- ------------ -------------- -------------
Balance,
December 31, 1999.......... 356,999 $ 3,570 18,837,699 $ 188,377 -- $ 84,877,904 $(52,737,101)
=========== ========== ============= =========== ============ ============== =============
</TABLE>
(1) As a result of the 1:6 reverse stock split effective 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,
----------------------------------------
1999 1998
----------------- ----------------
<S> <C> <C>
Cash flows from operating activities:
Net loss .......................................................... $ (10,250,238) $ (29,321,347)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depletion, depreciation and amortization ..................... 4,292,837 1,522,771
Amortization of unproven property............................. 7,546,000 6,937,300
Impairment of oil and gas properties.......................... 358,106 5,832,024
Exploration costs - dry hole.................................. 692,642 5,213,930
Gain on sale of assets........................................ (2,243,511) (5,375)
Amortization of financing costs............................... 101,587 136,677
Unrealized gain on commodity transitions...................... --- (128,936)
Changes in operating assets and liabilities:
Trade and affiliate receivables............................... (3,487,403) (3,846,298)
Prepaid expenses.............................................. (3,817,711) 126,906
Other assets.................................................. (323,119) (372,941)
Trade and affiliate payables.................................. 479,387 11,405,011
Revenue distribution payable.................................. 495,707 1,927,960
Accrued, deferred and other................................... 5,610,432 440,990
----------------- ----------------
Net cash used in operating activities......................... (545,284) (131,328)
----------------- ----------------
Cash flows from investing activities:
Capital expenditures - gas and oil properties...................... (19,478,942) (23,936,538)
Capital expenditures - other property and equipment................ (558,748) (300,724)
Proceeds from sale of assets....................................... 14,970,015 5,191,847
----------------- ----------------
Net cash used in investing activities........................... (5,067,675) (19,045,415)
----------------- ----------------
Cash flows from financing activities:
Proceeds from issuance of debt..................................... 8,920,000 15,800,000
Repayments of long-term debt....................................... (1,508,074) (8,641,494)
Preferred stock redeemed........................................... --- (859,610)
Preferred stock dividends paid..................................... --- (228,654)
Net Proceeds from issuance of common stock......................... 152,880 14,438,318
Cost of issuing stock.............................................. --- (1,376,193)
----------------- ----------------
Net cash provided by financing activities....................... 7,564,806 19,132,367
----------------- ----------------
Net increase (decrease) in cash and cash equivalents............... 1,951,847 (44,376)
Cash and cash equivalents at beginning of year.......................... 646,200 690,576
----------------- ----------------
Cash and cash equivalents at end of year................................ $ 2,598,047 $ 646,200
================= ================
37
<PAGE>
Supplemental disclosure of cash flow information:
Cash paid for interest............................................. $ 1,763,323 $ 835,186
Supplemental disclosure of non-cash investing and financing activities:
Sale of oil and gas properties in satisfaction
Of payable to affiliates...................................... $ 2,700,000 ---
Acquisition of assets........................................... 8,333,853 $ 54,218,750
Proxy costs..................................................... 316,503 287,173
Assumption of related liabilities............................... 923,252 3,380,659
Issuance of common stock........................................ 6,723,378 50,430,370
Issuance of preferred stock..................................... 687,223 ---
</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.
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 the sales are completed 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
$358,106 and $1,560,990 of impairment charges during 1999 and 1998,
respectively. Unproved properties are periodically assessed for impairment and,
if necessary, a loss is recognized. Pursuant to this process, additional
impairments of $4,271,034 were also recognized in 1998.
In addition, the $54,200,000 fair market value assigned to unproven gas
and oil exploration projects contributed by Esenjay Petroleum Corporation
("EPC") and Aspect Resources LLC ("Aspect") pursuant to certain acquisitions of
undeveloped exploration projects (the "Acquisitions") which closed on May 14,
1998 is, until such time as the book value of each such project is either
drilled and transferred to producing properties or is otherwise evaluated as
impaired, are being amortized on a straight-line basis over a period not to
exceed forty-eight months. Such amortization was $7,546,000 and $6,937,300 for
the years ended December 31, 1999 and 1998, respectively. The balance in this
amortizing group of unproven properties was 13,392,100 and 43,800,198 at
December 31, 1999 and 1998, respectively.
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,
1999 and 1998 was approximately $1,023,221 and $456,901, 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, 1999 and 1998 was approximately 114,721 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 1999
and 1998, the Company expensed $1,597,372 and $5,882,307 in geological and
geophysical costs, respectively, and $692,642 and $5,213,930 in dry hole costs,
respectively. For purposes of reporting cash flows, the Company adds back to
operating activities all exploration costs which have been previously
capitalized, such as dry hole costs.
FAIR VALUE OF FINANCIAL INSTRUMENTS - Statement of Financial Accounting
Standards No. 107. "Disclosures about Fair Value of Financial Instruments"
requires disclosure regarding the fair value of financial instruments for which
it is practical to estimate that value. The carrying amount of cash and cash
equivalents, accounts receivable and accounts payable, approximates fair market
value because of the short maturity of those instruments. The fair value of the
Company's long-term debt is estimated to approximate carrying value based on the
borrowing rates currently available to the Company for bank loans with similar
terms and average maturities.
The Company has interest rate and gas swap agreements that subject it
to off-balance sheet risk. 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, 1999 and 1998 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>
1999 1998
---------------- --------------
<S> <C> <C>
BASIC AND DILUTED EARNINGS PER SHARE
Weighted average common shares outstanding ...................................... 16,612,314 9,882,227
================ ==============
Basic and diluted loss per share................................................. $ (0.62) $ (2.97)
================ ==============
EARNINGS FOR BASIC AND DILUTED COMPUTATION
Net loss......................................................................... $(10,250,238) $(29,321,347)
Preferred share dividends........................................................ --- (48,136)
---------------- ---------------
Net loss to common shareholders (basic and diluted loss per share computation)... $(10,250,238) $(29,369,483)
================ ===============
</TABLE>
40
<PAGE>
2. RECENT EVENTS
On January 25, 2000, the Company closed a credit facility with Deutsche
Bank AG, New York branch. This facility provides for Deutsche Bank to loan up to
$29,000,000 to be available in two tranches. Tranche A is in the amount of
$20,000,000, with $12,000,000 established as the current available borrowing
base, and Tranche B is fully drawn in the amount of $9,000,000. Under the terms
and conditions of this facility, the facilities existing at December 31, 1999
with Duke Energy Financial Services, Inc. and Bank of America, NT&SA, were paid
in full utilizing approximately $15,800,000 of the available proceeds from
Deutsche Bank. Tranche A will mature on January 25, 2001, at which time any
remaining unpaid principle will convert to a five-year monthly amortizing term
loan. The Tranche B loan is payable interest only through April 30, 2001 after
which date the amount available decreases by 25% per quarter beginning April 30,
2000 with a final maturity in January of 2006. In addition, the Company must
remain in compliance with certain covenants required by Deutsche Bank, including
a redetermination of the borrowing base every six months. The company also is
required to assign an overriding royalty interest to Deutsche Bank for those
wells logged prior to the later of the maturity date of Tranche B or the Tranche
A termination date or the date the Tranche B Loan is repaid. The Company may
repurchase this overriding royalty interest prior to April 30, 2002, if all
Tranche B loans are repaid in full.
In February of 2000, in conjunction with its financing with Deutsche
Bank, the Company restructured all existing natural gas hedges with an affiliate
of Deutsche Bank. Pursuant to these hedges, the Company now has 9,381 MMBtu/day
of net production hedged in March, 2000, 9,031 MMBtu/day hedged for the second
quarter of 2000, 8,646 MMBtu/day for the third quarter of 2000, 8,278 MMBtu/day
for the fourth quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001,
6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third
quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All hedges
are at $2.45 per MMBtu. Concurrent with the restructuring of the hedges, the
Company was relieved of any liability or rights pursuant to all previously
existing natural gas hedges. An existing "collar" hedge arrangement on 280
barrels of oil per day in the first quarter of 2000, and 256 and 237 barrels of
oil per day in the second and third quarters of 2000, respectively, was
transferred to the Deutsche Bank affiliate at the existing $18.00 floor price
and $20.40 cap price. These positions were supplemented with oil hedges at
$21.03 per barrel on volumes of 238 barrels of oil per day in the fourth quarter
of 2000 and 175, 168, 161, and 154 barrels of oil per day in the first through
fourth quarters of 2001, respectively. First quarter 2000 hedges are estimated
to approximate 68% of the Company's natural gas and 53% of its oil production
for such quarter. Future percentages will vary.
In October of 1999 the Company entered a transaction wherein it sold an
interest in its Papalote Project which created a deferred gain on sale of
$1,797,707. This is shown as a deferred liability because, as part of the same
transaction, the Company incurred an obligation to conduct a 3-D seismic survey
over the project area at the Company's cost. Until the final cost to the Company
of this 3-D seismic survey is incurred, the gain on sale, if any, cannot be
calculated. The gain on sale, if any, will be recognized in 2000 after
anticipated completion of the 3-D seismic survey.
As a result of the above-referenced transactions, the Company has
hedged varying quantities of its natural gas and oil production through December
of 2001.
On March 20, 2000, the Company closed the sale of approximately 84.39%
of its interest in its Raymondville Project in Willacy County for net cash
proceeds of $10,585,981 million. Pursuant to this sale the Company sold
3,462,967 MCFE of its reserves classified as proven as of December 31, 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.
In 1999 and 1998 the Company issued 3,052,865 and 14,128,850 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
41
<PAGE>
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.
On May 12, 1999, the Company announced that on May 11, 1999 it had
signed a Plan and Agreement of Merger with 3DX Technologies Inc. ("3DX") which
provided for the merger of 3DX into the Company (the "Acquisition"). The
shareholders of both companies approved the transaction at duly called
shareholders meetings on September 23, 1999 and the merger was consummated the
same day. The purchase price of the Acquisition was approximately $7.4 million,
of which $6.7 million was in the Company's common stock and $0.7 million was in
the Company's preferred stock.
The terms of the merger provided for 3DX shareholders to receive, at
their election, either (i) the issuance of one share of Esenjay common stock for
3.25 shares of 3DX common stock; or (ii) the issuance of a new Esenjay
convertible preferred stock at a ratio of one share of Esenjay convertible
preferred stock for each 2.75 shares of 3DX common stock. Approximately 91% of
the 3DX common shares converted into Esenjay common stock and approximately 9%
were converted into Esenjay convertible preferred stock. As a result, Esenjay
issued approximately 2,906,778 new shares of common stock and approximately
356,999 shares of convertible preferred stock. The convertible preferred stock
may be redeemed at Esenjay's sole option until September 23, 2000 at $1.925 per
share. If not redeemed by that time, the preferred will automatically convert
into one share of Esenjay common stock on October 1, 2000 if the average closing
price of Esenjay common stock is greater than or equal to $1.875 during the
month of September 2000. If the Esenjay common stock averages less than $1.875
in September of 2000, the preferred holder has the right, during the month of
October of 2000, to "put" the shares to Esenjay. If put, Esenjay will then have
the right to retire the convertible preferred stock for $1.65 in cash or for
common stock with the number of shares of common stock adjusted based upon a
formula set out in the merger agreement. Under any scenario the convertible
preferred stock is scheduled to be converted or redeemed not later than November
1, 2000. Prior to that time no dividends accrue or are required to be paid other
than as would participate with any common stock dividends, which common stock
dividends are not anticipated to be declared.
In May of 1999, seven directors of the Company each subscribed for the
purchase of 12,000 shares of common stock of the Company for an aggregate total
of 84,000 shares. The shares were at a price of $1.83 per share payable
one-third upon subscription, one-third in May of 2000 and one-third in May of
2001. Shares are to be delivered in 2000. At December 31, 1999, the Company had
a common stock subscription receivable of $109,800 outstanding related to these
shares.
CUMULATIVE CONVERTIBLE PREFERRED STOCK - During 1998, $48,136 was
declared and paid in cumulative preferred stock dividends. In addition, during
1998 the Company paid dividends in arrears of $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, 1997, there were 263,013 Series A
Warrants outstanding. All of the Series A Warrants expired on November 13, 1998.
Since December 31, 1997, the Company has had Series B Warrants, which
entitles the holder to purchase one-sixth (1/6) share of common stock for $12.15
until August 8, 2001. Each Series B Warrant is redeemable by the Company with
the prior consent of the underwriter at a price of $0.06 per Series B Warrant,
at any time after the Series B Warrants become exercisable, upon not less than
30 days notice, if the last sale price of the common stock has been at least
200% of the then exercise price of the Series B Warrants for the 20 consecutive
trading days ending on the third day prior to the date on which the notice of
redemption is given.
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.
42
<PAGE>
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.
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 12,500 shares of common stock during 1998 and no shares in 1999.
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). The warrants were canceled in January of 2000 at which
time B of A was repaid all amounts due pursuant to the amended credit agreement.
EMPLOYEE OPTION PLANS - The Company has option plans for employees and
directors which authorize the issuance of up to 3,000,000 options to purchase
one share of common stock. Options to purchase 1,259,667 shares of common stock
at prices ranging from $1.83 to $3.78 are currently outstanding.
Under the plans, the Board may grant options to officers and other
employees. Each option shall consist of an option to purchase one share of
common stock at an exercise price that shall be at least the fair market value
of the Common stock on the date of the grant of the option. However, the Board
may authorize vesting options as it deems necessary. Unless otherwise so
designated, the options shall be exercisable at a rate of 33 1/3% in the year
following the effective date of the grant, and 33 1/3% each of the two years
thereafter. The Option holder's right is cumulative. Unless otherwise designated
by the Board, if the employment of the Option holder is terminated for any
reason, all unexercised Options shall terminate, be forfeited and shall lapse
within three months thereafter. The options have a maximum life of ten years
from the date of issuance.
43
<PAGE>
The following table summarizes activity under the Company's stock
option plans for the years ended December 31, 1999 and 1998.
<TABLE>
<CAPTION>
EMPLOYEE OPTION PLANS
--------------------------------------
1999 1998
------------------- -----------------
<S> <C> <C>
Shares available for grant............................... 3,000,000 115,892
Shares under option at end of period..................... 1,259,667 94,001
Option price per share................................... $1.83 - 3.78 $3.78-$7.68
Shares exercisable at end of period...................... 480,303 90,667
Shares forfeited......................................... --- ---
Weighted average option price............................ $2.42 $3.92
Weighted average fair value
of options granted during
the year at market price................................. $1.34 ---
</TABLE>
The Company has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation". Accordingly, no compensation cost has been recognized for the
stock option plans. Had compensation cost for the Company's stock option plans
been determined based on fair value at the grant date for awards in 1999 and
1998 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>
1999 1998
------------- -------------
<S> <C> <C>
Net loss applicable to common stockholders - as reported............................. $(10,250,238) $(29,369,483)
Net loss applicable to common stockholders - pro forma............................... $(11,247,486) $(41,198,653)
Net loss per common share-as reported................................................ $ (0.62) $ (2.97)
Net loss per common share-pro forma.................................................. $ (0.68) $ (2.50)
</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 80.99% and 60% in 1999 and
1998; risk-free interest rate of 5.625% and 5.71% in 1999 and 1998; and expected
lives of 10 years.
4. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA:
The Company sold various interests in a number of different projects,
prospects and wells during 1999 and 1998. These sales resulted in an aggregate
gain of approximately $2,243,511 in 1999. The Company recorded an deferred gain
on sale of $1,797,707 in relation to an ongoing sale in the Company's Papalote
project. As a part of the sales transaction the Company is required to conduct a
3-D seismic survey over the project area. The survey is currently being shot
over the project area and the gain on sale, if any, will be recognized upon the
completion of the 3-D seismic survey. No gain or loss was recorded on the sale
of oil and gas 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
incurred.
44
<PAGE>
5. LONG-TERM DEBT: (SEE NOTE 2)
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------
1999 1998
-------------- --------------
<S> <C> <C>
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 paid in 1999................................................. --- 1,236
Note payable, interest at 12%, payable monthly, is currently due.................. 100,000 100,000
Loan with Bank of America NT&SA ("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 as to 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 most properties currently owned by the Company..... 8,523,162 7,500,000
Loan with Duke Energy Field Services, Inc., which provided for up to
$9,000,000 to the Company for eighteen months pursuant to a decreasing
facility. The commitment reduces by $930,000 per, and reducing to zero on
August 1, 2000. Total available as of December 31, 1999 was $7,140,000. The
interest rate is prime plus 4%. The loan is secured by a mortgage on all
properties currently owned by the Company..................................... 7,140,000 ---
-------------- --------------
16,627,162 8,465,236
Less current portion.............................................................. 11,013,162 101,236
-------------- --------------
$5,614,000 $8,364,000
============== ==============
</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>
AT DECEMBER 31,
YEAR 1999(1)
---- ---------------
<S> <C>
2000.................................................................... 11,013,162
2001.................................................................... 950,000
2002.................................................................... 950,000
2003.................................................................... 950,000
2004.................................................................... 950,000
2005.................................................................... 950,000
</TABLE>
(1) All outstanding amounts shown were repaid with proceeds from the credit
facility with Deutsche Bank. (See Note 2 for maturities under this
facility over the next 5 years.)
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). 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
45
<PAGE>
closing of the credit agreement. Proceeds of the loan primarily supplement
working capital. As part of the credit agreement, the Company was 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 loan has been repaid. In the event the loan had not been repaid, the
Company would have to have requested a waiver. (See Note 2 - Recent Events.)
The Company has entered into an interest rate swap guaranteeing a fixed
interest rate of 5.37% on the loan, and the Company will pay fees of
three-eighths of 1% (.0375%) on the unused portion of the commitment amount. The
unrealized loss on the interest rate swap agreement was $1,558 at December 31,
1999. The actual rate for the Company is the fixed rate of 5.0% plus 2% on
Tranche A and the fixed rate of 5.0% plus 4% on Tranche B of the loans from B of
A. This swap was settled in January of 2000. (See Note 2 - Recent Events.)
On January 28, 1999, the Company closed a credit facility with Duke.
This facility provided for Duke to loan up to $9,000,000 to the Company for
eighteen months. The Company had $7,140,000 outstanding on said facility as of
September 30, 1999,which represented the total amount then available. The
commitment initially reduced by $930,000 per quarter until it would reduce to
zero on August 1, 2000. Effective November 1, 1999, the Company and Duke amended
the credit agreement such that there was no reduction in the available amount of
$7,140,000 on November 1, 1999. As a result, the commitment amount was scheduled
to reduce by $1,860,000 in February of 2000, $930,000 in May of 2000, and reduce
to 0 in August of 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. The note was repaid
in January 2000. (See Note2 - Recent Events).
6. INCOME TAXES:
Deferred tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
-------------------------------------
1999 1998
----------------- ---------------
<S> <C> <C>
Net operating tax loss carry forward............................ $ 17,590,565 $ 11,633,159
Property and equipment.......................................... 2,166,546 (435,246)
Valuation allowance............................................. (19,757,111) (11,197,913)
----------------- ---------------
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, 1999, of approximately $50,258,757 which may be used to
offset future taxable income. The operating loss carryforwards expire in the tax
years 2006 through 2019.
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, 1999 and 1998 were $472,827 and $963,700, respectively.
The December 31, 1999 and 1998 receivables include $47,787 from an affiliated
partnership for which the Company serves as the managing general partner. The
December 31,
46
<PAGE>
1999 and 1998 includes receivables of $190,923 and $915,342, respectively, from
Esenjay Petroleum Corporation (EPC) relating to joint interest billings. In
addition, at December 31, 1999 and 1998, the Company had a net payable to Aspect
in the amount of $2,083,913 and $4,322,548, respectively; in June 1999 the
Company closed a sale to Aspect of 12.5% (of 100%) interest in its Caney Creek
project and a 12% (of 100%) interest in the Gillock project, and all of the
Company's undeveloped interests in the West Beaumont project area for an
aggregate of approximately $2,700,000. Proceeds from the sale were used to
settle amounts due Aspect.
8. COMMITMENTS AND CONTINGENCIES:
The Company leases office space under lease agreements, which are
classified as operating leases. Lease expense under these agreements was
$291,169 in 1999 and $193,515 in 1998. A summary of future minimum rentals on
these non-cancelable operating leases is as follows:
<TABLE>
<CAPTION>
YEAR AT DECEMBER 31, 1999
---- --------------------
<S> <C>
2000.................................................................... $306,190
2001.................................................................... 248,445
2002.................................................................... 168,137
2003.................................................................... 84,068
</TABLE>
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.
In September of 1999, the Company entered into a series of swap
agreements on additional natural gas and oil production. It hedged 5,000 MMBtu's
per day of natural gas for the months of September through December 1999 at a
price of $3.055 per MMBtu, it hedged 3,000 MMBtu's per day for the period of
January through March of 2000, 2,400 MMBtu's per day for the period April
through June of 2000, and 1,700 MMBtu's per day for the period of July through
September of 2000, the latter three hedges of which were all at a price of $2.68
per MMBtu. In addition, the Company entered into a "collar" hedge arrangement on
certain of its oil production. This oil hedge was for a quantity equal to 300
barrels of oil per day in the fourth quarter of 1999, 280 barrels of oil per day
in the first quarter of 2000, 256 barrels of oil per day in the second quarter
of 2000, and 237 barrels of oil per day in the third quarter of 2000, all of
which transactions were structured with an $18.00 floor price and a $20.40 cap
price.
In January of 2000 the above hedge instruments were assumed by Deutsche
Bank AG and the natural gas hedges were restructured. (See Note 2 - Recent
Events.)
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
47
<PAGE>
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.
On May 12, 1999, the Company announced that on May 11, 1999 it had
signed a Plan and Agreement of Merger with 3DX Technologies Inc. ("3DX") which
provided for the merger of 3DX into the Company (the "3DX Acquisition"). The
shareholders of both companies approved the transaction at duly called
shareholders meetings on September 23, 1999 and the merger was consummated the
same day. The purchase price of the 3DX Acquisition was approximately $7.4
million, of which $6.7 million was in the Company's common stock and $0.7
million was in the Company's preferred stock. The 3DX Acquisition included, at
fair value, current assets of $2.5 million, property and equipment of $5.8
million, other assets of $0.1 million and liabilities of $0.9 million.
3DX Technologies Inc. was a Houston-based exploration and production
company whose strategic business focus was the utilization of 3-D seismic
imaging and other advanced technologies in the search for natural gas and oil
principally in the onshore gulf coast of the United States. As a result of the
merger, the Company employed four members of the reservoir engineering and
geophysical staff of 3DX, plus one support person, increased its gas and oil
reserves, its monthly gas and oil revenues, and expanded its ownership of 3D
seismic data and projects.
The acquisitions have been accounted for using the purchase method of
accounting and, accordingly, the purchase price has been allocated to the assets
and liabilities acquired based on fair value at the date of acquisition. The
operating results of the acquisitions have been included in the Company's
consolidated financial statements from their respective dates of acquisition.
The following unaudited pro forma information presents a summary of the
consolidated results of operations for the years ended December 31, 1999 and
1998 as if the acquisitions had occurred on January 1, 1998.
<TABLE>
<CAPTION>
1999 AND 1998 ACQUISITIONS: YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 1998
--------------------- ------------------
<S> <C> <C>
Revenues................................................... $ 14,176,091 $ 6,315,147
Total costs and expenses................................... 28,393,836 47,513,800
--------------------- ------------------
Net loss................................................... $ (14,217,745) (41,198,653)
===================== ==================
Basic and diluted loss per share........................... $ (0.73) $ (2.50)
===================== ==================
Weighted average number of common shares
Outstanding.......................................... 19,518,839 16,471,822
===================== ==================
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED
1998 ACQUISITION DECEMBER 31,
------------------
1998
------------------
<S> <C>
Revenues............................................................................. $ 1,716,473
Total costs and expenses............................................................. 33,325,677)
------------------
Net loss............................................................................. $ (31,609,204)
==================
Basic and diluted loss per share..................................................... $ (2.33)
==================
Weighted average number of common shares
outstanding.................................................................... 13,564,983
==================
</TABLE>
48
<PAGE>
10. PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1999 1998
--------------- --------------
<S> <C> <C>
Gas and oil properties, at cost, successful
efforts method of accounting:
Proved........................................... $ 30,586,079 $ 14,006,244
Unproved, subject to amortization .............. 13,392,100 43,800,198
Unproved, not subject to amortization............ 34,180,470 10,835,056
--------------- --------------
Total gas and oil properties.................. 78,158,649 68,641,498
Other property and equipment..................... 1,962,132 1,403,384
--------------- --------------
Total oil and gas properties and equipment................ 80,120,781 70,044,882
Less accumulated depletion, depreciation
and amortization..................................... (25,937,472) (15,517,656)
--------------- --------------
$ 54,183,309 $ 54,527,226
=============== ==============
</TABLE>
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED):
The Company's proved gas and oil reserves are located in the United
States. Proved reserves are those quantities of natural gas and crude oil which,
upon analysis of geological and engineering data, demonstrate with reasonable
certainty to be recoverable in the future from known gas and oil reservoirs
under existing economic and operating conditions (i.e. price and costs as of the
date the estimate is made). Proved developed (producing and non-producing)
reserves are those proved reserves which can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
gas and oil reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling units
offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation.
FINANCIAL DATA
The Company's gas and oil producing activities represent substantially
all of the business activities of the Company. The following costs include all
such costs incurred during each period, except for depreciation and amortization
of costs capitalized:
COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998
-------------- -----------
<S> <C> <C>
Acquisition of properties:
Proved......................................................................... $ 848,505 $ ---
Unproved....................................................................... 5,214,982 63,511,000
Exploration costs................................................................. 11,577,425 13,412,133
Development costs................................................................. 859,349 7,114,820
-------------- -----------
Total costs incurred........................................................ $ 18,500,261 $84,037,953
============== ===========
</TABLE>
49
<PAGE>
CAPITALIZED COSTS:
<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------------
1999 1998
-------------- -------------
<S> <C> <C>
Proved.......................................................................... $ 30,586,079 $ 14,006,244
Unproved properties, subject to amortization.................................... 13,392,100 43,800,198
Unproved properties, not subject to amortization................................ 34,180,470 10,835,056
Less accumulated amortization................................................... (24,828,022) (14,584,784)
-------------- -------------
Net capitalized costs..................................................... $ 53,330,627 $ 54,056,714
============== =============
</TABLE>
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE AND
NATURAL GAS LIQUIDS
NATURAL GAS (MCF) (BARRELS)
----------------- --------
YEARS ENDED DECEMBER 31, YEARS ENDED DECEMBER 31,
--------------------------------- -------------------------
1999 1998 1999 1998
-------------- ------------ ------------ ----------
<S> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of period............................. 11,929,667 5,500,363 100,195 114,399
Purchases of minerals-in-place.................. 291,055 --- 4,802 ---
Sales of minerals-in-place...................... --- --- --- ---
Revisions of previous estimates................. (6,027,430) (5,284,456)(1) (45,872) (97,420)(1)
Extensions, discoveries and other additions..... 15,981,338 12,367,076 414,229 92,094
Production...................................... (3,381,592) (653,316) (100,559) (8,878)
--------------- ------------ ------------ ----------
End of period................................... 18,793,038 11,929,667 372,795 100,195
=============== ============ ============ ==========
Proved developed reserves:
Beginning of period............................. 6,864,564 521,345 59,085 24,358
End of period................................... 17,481,248 6,864,564 371,368 59,085
</TABLE>
(1) Revision required because the reduced market price for oil and natural
gas caused the Company to reassess the likelihood of drilling marginal
wells, particularly in the Starboard Project. As a result, wells that
had been included in previous estimates were removed because it was now
more likely than not that these wells would not be drilled because of
the reduced market price.
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, 1999 and 1998 were as follows: 1999 $2.30 per Mcf
of natural gas, $22.20 per barrel of oil; 1998 - $2.01 per Mcf of natural gas,
$9.03 per barrel of oil, respectively. Future net cash flows are then calculated
by reducing such estimated cash inflows by the estimated future expenditures
(based on current costs) to be incurred in developing and producing the proved
reserves and by the estimated future income taxes. Estimated future income taxes
are computed by applying the appropriate year-end tax rate to the future pretax
net cash flows relating to the Company's estimated proved oil and gas reserves.
The estimated future income taxes give effect to permanent differences and tax
credits and allowances.
50
<PAGE>
The following table sets forth the Company's estimated standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1999 1998
-------------- -----------
<S> <C> <C>
Future cash inflows............................................................. $49,970,700 $25,241,119
Future development and production costs......................................... (10,635,400) (8,478,613)
Future income tax expenses...................................................... --- ---
-------------- -----------
Future net cash flows........................................................... 39,335,300 16,762,506
Discount........................................................................ 6,822,200 (4,242,485)
-------------- -----------
Standardized measure of discounted future net cash flows........................ $32,513,100 $12,520,021
============== ===========
</TABLE>
The following table sets forth changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1999 1998
----------------- -------------
<S> <C> <C>
Standardized measure of discounted future cash flows-beginning of period....... $12,520,021 $3,898,500
Sales of oil and gas produced, net of operating expenses....................... (9,037,645) (1,021,830)
Purchases of minerals in place................................................. 817,070 ---
Net changes in sales prices and production costs............................... 1,067,500 (4,459,331)
Extensions, discoveries and improved recovery, less related costs.............. 47,838,148 13,358,762
Change in future development costs............................................. 1,351,700 5,135,315
Previously estimated development costs incurred during the year................ (9,353,624) 2,515
Revisions of previous quantity estimates....................................... (14,486,234) (1,957,356)
Accretion of discount.......................................................... 2,212,137 402,566
Net change of income taxes..................................................... --- 127,157
Sales of minerals-in-place..................................................... --- ---
Changes in production rates (timing) and other................................. (415,973) (2,966,277)
----------------- -----------
Standardized measure of discounted future cash flows-end of period............. $32,513,100 $12,520,021
================ ===========
</TABLE>
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
51
<PAGE>
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT
The following table sets forth certain information regarding the
Company's directors and executive officers.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
David W. Berry(1)(6)................................. 50 Chairman of the Board
Alex M. Cranberg(1)(2)(4)............................ 45 Vice Chairman of the Board
Michael E. Johnson(1)(4)............................. 51 Director, President and Chief Executive Officer
C. Eugene Ennis(7)................................... 56 Director
Alex B. Campbell(3)(6)............................... 42 Director
William D. Dodge, III(2)(5).......................... 47 Director
Jack P. Randall(1)(3)(4)............................. 50 Director
Hobart A. Smith(2)(3)(5)............................. 63 Director
Jeffrey B. Pollicoff(6).............................. 47 Director
David B. Christofferson.............................. 51 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 2000.
(5) Director whose term expires in 2001
(6) Director whose term expires in 2002
(7) Director elected to represent preferred shareholders whose term expires
when the preferred stock is converted or redeemed. Preferred stock is
to be redeemed or convert not later than November 1, 2000.
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 Independent Petroleum Association of America.
ALEX M. CRANBERG has been a director of the Company since May 14, 1998.
He has been President of Aspect Management Corporation, the manager of Aspect,
since its inception in 1993. He joined Houston Oil and Minerals Corp. in 1977
where he served in various engineering and financial roles. He has managed the
oil and gas portfolio of General Atlantic Partners, a private investment firm,
since 1981. He is on the Board of Directors of Brigham Exploration, Inc., a
public company, and Westport Oil and Gas, Inc., a 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.
C. EUGENE ENNIS has been a director of the Company since September 23,
1999. He served as chairman of the board of 3DX Technologies Inc. since 1998.
Mr. Ennis served as 3DX's president and chief executive officer from 3DX's
inception in December 1992 until June 1998. Since September 1998, Mr. Ennis has
been a director of Object
52
<PAGE>
Reservoir, a supplier of software tools for the petroleum industry. Mr. Ennis
has been chief executive officer of Object Reservoir since January 1999. From
September 1984 to December 1992, Mr. Ennis was president, chief executive
officer and a director and from October 1990 to December 1992 was also chairman
of the board of directors of Landmark Graphics Corporation ("Landmark"), a
provider of interdisciplinary interpretation tools for the petroleum industry.
Mr. Ennis holds a Bachelor of Science in electrical engineering from the
University of Houston and began his career in 1969 as a design engineer in the
Geophysical Products Division of Texas Instruments where he was employed until
1984.
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 is co-founder and President of Houston-based Randall & Dewey, Inc.,
a full-service transaction advisory firm focusing solely on upstream oil and
gas mergers, acquisitions, divestments, trades and alliances. Its clients
include a cross section of companies ranging from the major oil companies to
small private independents. Prior to co-founding Randall & Dewey with Ken
Dewey, Mr. Randall was with Amoco Production Company for 15 years. He held
his last position, Manager of Acquisitions and Divestments, for seven years.
Mr. Randall is a graduate of The University of Texas (Austin) with a BS in
Engineering (1972) and an MS in Engineering (1975). He is a member of the
Board of Directors of Cross Timbers Oil Company and Esenjay Exploration,
Inc.; the Engineering Foundation Advisory Committee at the University of
Texas as well as Chairman of the Petroleum Engineering Visiting Committee.
Mr. Randall is also on the Board of Directors of the Sam Houston Council of
the Boy Scouts of America as well as District Chairman of the Rising Star
District; the M.D. Anderson Cancer Center Board of Visitors as well as being
a member of the SPE, API and IPAA.
HOBART A. SMITH has been a director of the Company since May 14, 1998.
He has served as a director of Harken Energy Corporation since 1997 and a
consultant to Smith International, Inc. since 1991. From 1987 to 1991, Mr. Smith
was Vice President of Customer Relations for Smith International, Inc. From 1965
to 1987, he held numerous positions, including many executive offices with Smith
Tool, Inc., a subsidiary of Smith International, Inc. Mr. Smith has more than 30
years of experience in the oil services industry. Mr. Smith received a BA from
Claremont McKenna College.
JEFFREY B. POLLICOFF has been a director of the Company since November
10, 1999. Mr. Pollicoff has been the Managing Partner with Pollicoff, Smith &
Remels, L.L.P. since 1991, and has been with the firm since 1982. From 1981 to
1982, Mr. Pollicoff served as Executive Vice President of Norris Petroleum
Company and Care Drilling Company. From 1979 to 1981, Mr. Pollicoff served as
Vice President and Energy Loan Officer for Texas Commerce Bank. From 1974 to
1979, he held several engineering positions at Atlantic Richfield Corporation.
Mr. Pollicoff is a member of the American Bar Association, State Bar of Texas,
Houston Bar Association and College of the State Bar of Texas. He received a BS
decree in Electrical Engineering from Texas A&M University in 1974 and a J.D.
from the University of Houston Law School in 1980.
DAVID B. CHRISTOFFERSON joined the Company in 1989 and served as a
director until May 14, 1998. Mr. Christofferson currently is Senior Vice
President, Secretary and General Counsel of the Company. He also serves as its
Principal Financial Officer. Mr. Christofferson has been active in the natural
gas and oil industry for over 20 years. He also served as General Counsel to two
independent natural gas and oil companies and to a natural gas marketing
company. Mr. Christofferson is a member of the Texas Independent Producers and
Royalty Owners Association. He received a BBA in finance and a Juris Doctor from
the University of Oklahoma. He also received a Masters of Divinity degree from
Phillips University. He is admitted to practice law in Oklahoma.
53
<PAGE>
KEY OFFICERS
In addition to the directors and executive officers listed above, the
following former EPC employees have significant responsibilities with the
Company.
DALE W. ALEXANDER, 44, 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.
GARY M. BEARD, 51, is Vice President-Land. Mr. Beard joined the
Company in September 1999 when he became the Company's Vice President of
Land. From 1997 to 1999, he served as Project Supervisor with Contract Land
Staff, Inc. He was a landman with Union Pacific Resources Company from 1994
to 1997. From 1990 to 1996 he was Vice President of PetraTexas Resources,
Inc. From 1983 to 1990, he served as President of Gary Beard & Associates. He
also worked for Donald C. Slawson and Universal Resources Corporation. Mr.
Beard has a BS in Biology and Chemistry and a MS in biochemistry from the
University of Central Oklahoma.
ERIC GARDNER, 36, is Exploration Manager in the Houston office. Mr.
Gardner joined the Company in September of 1999. From 1994 to 1999 he served
as project leader and senior explorationist at 3DX Technologies Inc. From
1985 to 1994 he was a senior geophysicist at Amoco Production Company. He
received a BS in Engineering Physics from Colorado School of Mines in 1985.
WILLIAM L. JACKSON, 44, is Senior Vice President-Operations. Mr.
Jackson joined EPC in 1982 and, on May 14, 1998, became the Company's Chief
Engineering Officer responsible for all oil and gas drilling, completion,
workover, and production operations. He previously served with Acock Engineering
and Mueller Engineering as an on-site petroleum engineering consultant on
drilling and workovers for oil and gas wells in the South Texas area. He
received a BS in Petroleum Engineering and an MBA from the University of Texas.
MICHAEL E. MOORE, 42, is Vice President-Exploration. Mr. Moore
joined EPC in 1982 as a staff geologist and became the Company's Vice
President-Exploration on May 14, 1998. Mr. Moore is responsible for reviewing
all outside geological projects as well as supervising the activities of
in-house and retainer geological staff. He previously was employed as a field
geologist with J.R. Weber, Inc., a consulting firm in Denver, Colorado. He
received a BS in Geology from the University of Texas.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires the Company's directors,
executive officers and persons who own more than 10% of a registered class of
the Company's equity securities, to file reports of ownership on Form 3 and
changes in ownership on Form 4 or 5 with the Commission. Such officers,
directors and 10% shareholders also are required by Commission rules to furnish
the Company with copies of all Section 16(a) reports they file. Based solely on
its review of the copies of such forms received by it, or written
representations from certain reporting persons that they were not required to
file a Form 5, the Company believes that, during the fiscal year ended December
31, 1999, its officers, directors and 10% shareholders complied with all Section
16(a) filing requirements applicable to such individuals other than Esenjay
Petroleum Corporation, Michael E. Johnson and Charles J. Smith, who each filed
one late report covering the same two transactions, David W. Berry, who filed
one late report covering three transactions, Alex B. Campbell, who filed one
late report covering 658 shares of common stock, and Jeffrey B. Pollicoff, who
filed one late report covering 2,000 shares of common stock of the Company he
held prior to becoming a director.
ITEM 10. EXECUTIVE COMPENSATION
The following table sets forth the total remuneration paid during 1999,
1998 and 1997 to the individuals who served as Chief Executive Officer of the
Company during 1999 and the Company's other most highly compensated
54
<PAGE>
officers who received compensation in excess of $100,000 during 1999.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
------------------------------------
ANNUAL COMPENSATION(1) AWARDS PAYOUTS
--------------------------- ---------------------- ----------
NAME SECURITIES
AND OTHER (RESTRICTED UNDERLYING ALL
PRINCIPAL ANNUAL STOCK OPTIONS/ LTIP OTHER
POSITION YEAR SALARY($) BONUS($) COMPENSATION AWARD(S) SARS(#) PAYOUTS COMPENSATION($)
-------- ---- --------- -------- ------------ ------- -------- ------- ---------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Michael E. Johnson(3)....... 1999 $200,000 ------ ------ ------ ------ ------ (9)
President and
Chief Executive Officer 1998 $125,000 ------ ------ ------ ------ ------ ------
David W. Berry(4)........... 1999 $155,000 ------ ------ ------ ------ ------ (9)
Chairman of the Board 1998 $147,079 ------ ------ ------ ------ ------ $264,000(5)
1997 $134,400 ------ ------ ------ 32,000(6) $44,965(7) ------
David B Christofferson...... 1999 $130,000 ------ ------ ------ ------ ------ (9)
Senior Vice President and 1998 $121,606 ------ ------ ------ ------ ------ $224,000(5)
Principal Financial
Officer 1997 $112,000 ------ ------ ------ 58,667(6) $47,888(8) ------
William L. Jackson.......... 1999 $114,700 ------ ------ ------ ------ ------ (9)
Senior Vice President -
Operations 1998 $ 71,688 ------ ------ ------ ------ ------ ------
</TABLE>
(1) Does not include perquisites and other personal benefits which are the
lesser of either $50,000 or 10% of the total of annual salary and
bonus.
(2) Represents the number of shares of Common Stock issuable pursuant to
vested and non-vested stock options.
(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 promisory 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 an employee option 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 $22,476 is reported as earned in 1997.
(9) The Company has instituted a bonus plan which is significantly based
upon dollars expended during a given year on drilling and completion
costs and the present value return in the form of net revenue received
and projected to be received as determined by engineering evaluation of
such drilled projects. This will result in bonus compensation
reportable for the year 2000 equal to a range of 48-64% of the salary
of each individual named in this Summary Compensation Table. The bonus
may be paid up to 50% in common stock, based upon market value at the
time of issuance, at the election of the Company.
OPTION GRANTS OR REPRICINGS
There were no option grants or repricings made in 1999 to the
individuals named in the Summary Compensation Table above.
OPTION EXERCISE AND YEAR-END VALUES
The following table sets forth certain information as of December 31,
1999 with respect to the unexercised options to purchase Common Stock to the
individuals named in the Summary Compensation Table above.
None of such individuals exercised any stock options during 1999.
55
<PAGE>
AGGREGATED OPTIONS/SAR EXERCISES IN 1999
AND DECEMBER 31, 1999 OPTION/SAR VALUES
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES VALUE OF
UNDERLYING UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS/SARS AT OPTIONS/SARS AT
DECEMBER 31, 1999 DECEMBER 31, 1999
SHARES
ACQUIRED VALUE EXERCISABLE/ EXERCISABLE/
NAME ON EXERCISE(#) REALIZED($) UNEXERCISABLE(1) UNEXERCISABLE(2)
- ------------------------------- --------------- ----------------- --------------------- ------------------
<S> <C> <C> <C> <C>
David W. Berry............. ------ ------ 32,000/0 0/0
David B Christofferson..... ------ ------ 58,667/0 0/0
</TABLE>
- --------------
(1) The Company's Employee Option Plan - 1997 authorizes the issuance of
90,667 options to purchase one share of Common Stock. Options to
purchase 90,667 shares of Common Stock are currently outstanding at an
exercise price of $3.78 per share. Options for the executive officers
noted are included in this plan. Options expire the earlier of 90 days
after employment has ended or November 2007.
(2) Based on the last sale price of the Common Stock on the Nasdaq
Small-Cap Market on December 31, 1999 of $1.875.
LONG TERM INCENTIVE PLANS
There were no awards pursuant to any long term incentive plan during
the year 1999.
DIRECTORS' COMPENSATION
The Board of Directors has adopted a standard compensation policy for
each of its directors whereby each director is paid a quarterly fee of $5,625.
There are currently no additional amounts paid for committee participation or
special assignments.
The Board of Directors has also instituted a standardized compensation
arrangement for each director who began service on the Board of Directors of the
Company on May 15, 1998. In this regard, each director was issued, in April of
2000, an option to purchase 12,000 share of Common Stock of the Company at an
exercise price of $1.83 per share exercisable through May 15, 2008, and in
addition, provided that said director still serves on the Board of Directors on
May 15, 2000, an option to purchase an additional 12,000 shares of the Common
Stock of the Company at a price of $2.10 per share exercisable through May 15,
2009, and, provided that said director still serves on the Board of Directors on
May 15, 2001, an option to purchase an additional 12,000 shares of the Common
Stock of the Company at a price of $2.38 per share exercisable through May 15,
2010. In conjunction therewith, each such director has also purchased and in
April of 2000 been issued 12,000 shares of Common Stock of the Company at a
price of $1.83 per share payable one-third upon subscription, one-third on or
before May 15, 2000, and one-third on or before May 15, 2001. This standard
arrangement affected all currently serving directors other than C. Eugene Ennis
and Jeffrey B. Pollicoff, neither of whom served on the Board of Directors of
the Company in 1998.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
EMPLOYMENT CONTRACTS
There were no employment contracts in effect with any named executive
officer in 1999.
BENEFICIAL OWNERSHIP OF COMMON STOCK
The following table sets forth certain information, as of April 28,
2000, 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 1999
56
<PAGE>
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.
<TABLE>
<CAPTION>
NUMBER OF PERCENT OF
NAME OF BENEFICIAL OWNER SHARES (1) CLASS (2) (3)
- ------------------------ ---------------------------- ------------------
<S> <C> <C>
Esenjay Petroleum Corporation(4)................. 4,908,915(5) 26.03%
Aspect Resources LLC(6).......................... 4,661,856(7) 24.72%
David W. Berry(8)................................ 286,832(9)(10) 1.52%
Alex M. Cranberg(6).............................. 4,751,968(10)(11) 25.20%
Michael E. Johnson(4)............................ 5,039,846(10)(12) 26.73%
Charles J. Smith(4).............................. 4,994,915(12) 26.49%
Alex B. Campbell(6).............................. 36,658(10) *
William D. Dodge, III(8)......................... 36,000(10) *
Jack P. Randall(8)............................... 36,000(10) *
Hobart A. Smith(8)............................... 37,667(10) *
C. Eugene Ennis(8)............................... 116,928 *
Jeffrey B. Pollicoff(8).......................... 2,000 *
William L. Jackson(4)............................ 65,735(13) *
David B Christofferson(8)........................ 174,387(14) *
All executive officers and Directors as a group (11 persons) 604,883(15). 3.21%
</TABLE>
- --------------------------
* Less than 1%
(1) Includes all shares of Common Stock with respect to which each person,
executive officer or Director who directly, through any contract,
arrangement, understanding, relationship or otherwise, has or shares
the power to vote or to direct voting of such shares or to dispose or
to direct the disposition of such shares. Includes shares that may be
purchased under stock options exercisable within 60 days.
(2) Based on 18,857,251 shares of Common Stock outstanding at April 28,
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 or warrants. Any shares a Stockholder is
deemed to own by having the right to acquire by exercise of a stock
option or warrant are considered to be outstanding solely for the
purpose of calculating that Stockholder's ownership percentage.
(4) Address: c/o Esenjay Exploration, Inc., 500 North Water Street, Suite
1100 South, Corpus Christi, Texas 78471.
(5) 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) Address: c/o Esenjay Exploration, Inc., 500 Dallas, Suite 2920,
Houston, Texas 77002
(9) Includes 32,000 shares of Common Stock issuable upon the exercise of
stock options currently exercisable which options were issued prior to
December 31, 1999.
(10) Includes 24,000 shares of Common Stock issuable upon the exercise of
stock options currently exercisable or exercisable within sixty days
which options were issued after December 31, 1999.
(11) Includes (i) 54,112 shares of Common Stock owned by the spouse of Mr.
Cranberg, and (ii) 4,661,856 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.
(12) Includes 4,896,415 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.
(13) Includes 50,000 shares of Common Stock issuable upon the exercise of
stock options currently exercisable or exercisable within sixty days
which options were issued after December 31, 1999, and 1,753 shares of
Common Stock owned by the spouse of Mr. Jackson.
(14) Includes 58,667 shares of Common Stock issuable upon the exercise of
stock options that were issued prior to December 31, 1999 that are
currently exercisable, and 100,000 shares of Common Stock issuable upon
the exercise of stock options currently exercisable or exercisable
within sixty days that were issued after December 31, 1999.
57
<PAGE>
(15) Includes 408,667 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.
BENEFICIAL OWNERSHIP OF PREFERRED STOCK
None of the Company's shares of outstanding preferred stock are owned
by its officers, directors, or partners who beneficially own 5% or more of the
Company's outstanding common stock.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company and Aspect Management Corporation, the manager of Aspect
("Aspect Management"), entered into a Geotechnical Services Consulting Agreement
on May 14, 1998, pursuant to which Aspect Management may perform geotechnical
services for the Company. To the extent that Aspect Management pays or advances
costs or expenses associated with certain assets on behalf of the Company, and
to the extent Aspect Management hires independent contractors, such costs and
expenses will be billed to the Company. Under the Geotechnical Services
Consulting Agreement, Aspect Management must obtain the Company's approval to
enter into any related contract or agreement that has a cost exceeding $50,000
net to the Company. The Company must pay Aspect Management for services rendered
in an amount equal to Aspect's employee costs, overhead costs and general and
administrative costs associated with the services rendered thereunder. The
agreements terminate on May 14, 2002, unless terminated by either party with 90
days' written notice to the other party. No such services were provided in 1999
under this agreement.
The Company and Aspect Management also entered into a Land Service
Consulting Agreement on May 14, 1998, pursuant to which Aspect Management could
provide certain land related services to the Company in connection with certain
oil and gas properties to which both parties share an ownership interest. This
agreement contained terms and provisions similar to the above-referenced
Geotechnical Services Consulting Agreement. No services were provided pursuant
to this Land Service Consulting Agreement in 1999 and the parties agreed to
terminate the agreement. It is no longer in effect.
Aspect received warrants in 1998 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 also received warrants in 1998 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 in 1998 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.
In the second quarter of 1999, the Company closed an agreement pursuant
to which it sold to Aspect a 12.5% (of 100%) interest in the Caney Creek
Project, a 12% (of 100%) interest in the Gillock Project, and all of the
Company's undeveloped property interests in the West Beaumont project area for
$2,610,000. Proceeds from the sale were used to help settle amounts due Aspect.
In that Aspect is a related party, closing was subject to receipt of an
independent fairness opinion which was obtained.
The Company operates certain wells in which Aspect and EPC own
interests. Pursuant to joint operating agreements which include the same terms
as apply to unrelated third parties, Aspect and EPC pay normal operation costs
associated with such wells. Conversely, Aspect operates certain wells in which
the Company owns interests. Pursuant to joint operating agreements which include
the same terms as apply to unrelated third parties, the Company pays normal
operation costs associated with such wells.
In 1999 the Company retained the firm of Randall and Dewey, Inc.
("Randall and Dewey") to assist in the marketing and sale of interests in its
Raymondville Project in Willacy County, Texas. Jack P. Randall, a director of
the Company, is also President and CEO and a substantial shareholder of Randall
and Dewey. Pursuant to the agreement with Randall and Dewey, the Company
reimbursed Randall and Dewey for $30,715 in costs incurred in 1999. In
addition, upon closing of a sale of interests in the Raymondville Project in
March of 2000, the Company paid Randall and Dewey a transaction fee of
$382,192. This fee included a base transaction fee of $250,000 plus 0.75% of
the total selling price. The Company's share of the fee was approximately
80.88% with third parties who also sold interests in the Raymondville
Project, including EPC, reimbursing the Company
58
<PAGE>
for their 19.12% pro rata share of the total fee. The Company believes the fee
charged was the normal fee which would be charged to third parties for
comparable services.
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 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, 1999 and 1998 was $472,827 and $963,700, respectively.
The December 31, 1999 and 1998 receivables include approximately $47,787 from an
affiliated partnership for which the Company serves as the managing general
partner. In addition, the December 31, 1999 balance includes a $190,923
receivable from EPC primarily related to joint interest billings to EPC. The
Company had a 2,083,913 account payable to Aspect at December 31, 1999.
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
EXHIBIT NAME OF EXHIBIT
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.
2(e) Plan and Agreement of Merger of Esenjay Exploration, Inc. and 3DX
Technologies Inc. is incorporated by reference to the Company's
Quarterly Report on Form 10QSB for the quarter ended March 31, 1999
dated May 19, 1999 wherein the same appears as Exhibit 2.
3(a) Certificate of Incorporation of the Company as incorporated by
reference to the Company's Registration Statement number 333-53581
dated May 21, 1998 wherein the same appeared as Exhibit 3(a).
3(b) By-Laws of the Company as incorporated by reference to the Company's
Registration Statement number 333-53581 dated May 21, 1998 wherein the
same appeared as Exhibit 3(c).
4(a) See Articles V, VI and X of the Company's Certificate of Incorporation
and Articles I, II, V and VI of the Company's By-Laws as provided at
Exhibits 3(a) and 3(b) above.
4(b) Certificate of Designations of Esenjay Exploration, Inc. establishing
the designations, preferences, limitations, and relative rights of its
Series A Convertible Preferred Stock is incorporated by reference to
the Company's Quarterly Report on Form 10-QSB for the quarter ended
September 30, 1999 dated November 15, 1999 wherein the same appears as
Exhibit 4.
10(a) 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,
60
<PAGE>
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
incorporated by reference to the Company's Annual Report on Form 10-KSB
for the fiscal year ended December 31, 1998 dated April 14, 1999,
wherein the same appears as Exhibit 10(d).
10(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).
10(m) Credit Agreement by and between Esenjay Exploration, Inc. and Deutsche
Bank AG, New York and/or Cayman Islands Branches, dated as of January
25, 2000, as currently in effect.
11* Statement of Earnings per Share
21* Subsidiaries of Registrant.
27* Financial Data Schedule.
(b) Reports on Form 8-K.
Form 8-K filed on October 8, 1999 is incorporated by reference.
- -----------------------
*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.
<TABLE>
<S><C>
ESENJAY EXPLORATION, INC.
Date: April 28, 2000 By: /s/ Michael E. Johnson
-------------------------------------------------
Michael E. Johnson, President,
Chief Executive Officer and Director
</TABLE>
Pursuant to the requirements of Section 13, or 15(d) of the Securities
and Exchange Act of 1934, the registrant has duly caused this report to be
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
<TABLE>
<S> <C>
Date: April 28, 2000 /s/ David B Christofferson
-------------------------------------------------
David B Christofferson, Senior Vice President
General Counsel and Chief Financial Officer
Date: April 28, 2000 /s/ Angela D. Conway
-------------------------------------------------
Angela D. Conway, Controller and
Principal Accounting Officer
Date: April 28, 2000 /s/ David W. Berry
-------------------------------------------------
David W. Berry, Chairman and Director
Date: April 28, 2000 /s/ Alex B. Campbell
-------------------------------------------------
Alex B. Campbell, Director
Date: April 28, 2000 /s/ William D. Dodge, III
-------------------------------------------------
William D. Dodge, III, Director
Date: April 28, 2000 /s/ C. Eugene Ennis
-------------------------------------------------
C. Eugene Ennis, Director
Date: April 28, 2000 /s/ Jeffrey B. Pollicoff
-------------------------------------------------
Jeffrey B. Pollicoff, Director
Date: April 28, 2000 /s/ Jack P. Randall
-------------------------------------------------
Jack P. Randall, Director
Date: April 28, 2000 /s/ Hobart A. Smith
-------------------------------------------------
Hobart A. Smith, Director
</TABLE>
62
<PAGE>
EXHIBIT 11 TO FORM 10-KSB/A
COMPUTATION OF EARNINGS PER COMMON SHARE AND COMMON SHARE EQUIVALENTS
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------
1999 1998
---------------- ----------------
<S> <C> <C>
BASIC EARNINGS PER SHARE
Weighted average common shares outstanding................................ 16,612,314 9,882,227
================ ================
Basic loss per share.................................................. $ (0.62) $ (2.97)
================ ================
DILUTED EARNINGS PER SHARE
Weighted average common shares outstanding................................ 16,612,314 9,882,227
Shares issuable from assumed conversion of
convertible preferred stock........................................ 96,830 ---
Shares issuable from assumed conversion of
common share options and warrants..................................... 10,437 40,123
---------------- ----------------
Weighted average common shares outstanding, as adjusted................... 16,719,581 9,922,350
================ ================
Diluted loss per share................................................ $ (0.61) $ (2.96)
================ ================
EARNINGS FOR BASIC AND DILUTED COMPUTATION
Net income................................................................ $(10,250,238) $(29,321,347)
Preferred shares dividend................................................. --- (48,138)
---------------- ----------------
Net income to common shareholders (basic and diluted
earnings per share computation)....................................... $(10,250,238) $(29,369,485)
================ ================
</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/A
The subsidiaries of the Registrant are:
Name State of Incorporation
- ---- ----------------------
Frontier Acquisition Corp. Oklahoma
64
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 2,598,047
<SECURITIES> 0
<RECEIVABLES> 7,597,246
<ALLOWANCES> (519,137)
<INVENTORY> 0
<CURRENT-ASSETS> 13,979,316
<PP&E> 80,120,781
<DEPRECIATION> (25,937,472)
<TOTAL-ASSETS> 68,932,835
<CURRENT-LIABILITIES> 30,522,690
<BONDS> 4,750,000
0
3,570
<COMMON> 188,377
<OTHER-SE> 32,140,803
<TOTAL-LIABILITY-AND-EQUITY> 68,932,835
<SALES> 9,781,352
<TOTAL-REVENUES> 12,566,165
<CGS> 0
<TOTAL-COSTS> 22,816,403
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 871,501
<INCOME-PRETAX> (10,250,238)
<INCOME-TAX> 0
<INCOME-CONTINUING> (10,250,238)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (10,250,238)
<EPS-BASIC> (0.62)
<EPS-DILUTED> (0.62)
</TABLE>
