<PAGE>
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-QSB
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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: 1-12530
ESENJAY EXPLORATION, INC.
(Exact name of small business issuer as specified in its charter)
DELAWARE 73-1421000
(State or other jurisdiction of
incorporation or organization) (I.R.S. Employer Identification Number)
500 NORTH WATER STREET, SUITE 1100
CORPUS CHRISTI, TEXAS 78471
(Address of principal executive offices including zip code)
(361) 883-7464
(Issuer's telephone number including area code)
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 [ ]
15,823,271 shares as the registrant's common stock were outstanding as of
August 10, 1999.
Transitional Small Business Disclosure Format (Check one): Yes [ ] No [ X ]
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<PAGE>
ESENJAY EXPLORATION, INC.
FORM 10-QSB
FOR THE QUARTER ENDED JUNE 30, 1999
INDEX
<TABLE>
<CAPTION>
PAGE
<S> <C>
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements - General Information......................................................3
Condensed Consolidated Balance Sheets as of June 30, 1999 (unaudited) and
December 31, 1998..........................................................................4
Condensed Consolidated Statements of Operations for the three months and six months
ended June 30, 1999 and 1998 (unaudited)...................................................5
Condensed Consolidated Statements of Cash Flows for the six months
ended June 30, 1999 and 1998 (unaudited)...................................................6
Notes to Condensed Consolidated Financial Statements (unaudited)................................7
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................................................10
PART II. OTHER INFORMATION..............................................................................21
</TABLE>
2
<PAGE>
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
GENERAL
The Condensed Consolidated Financial Statements herein have been
prepared by the Company without audit, pursuant to the rules and regulations of
the Securities and Exchange Commission (the "SEC"). As applicable under such
regulations, certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted. The Company believes the presentation
and disclosures herein are adequate to make the information not misleading, and
the financial statements reflect all elimination entries and normal adjustments
which are necessary for a fair presentation of the results of operations for the
three and six months ended June 30, 1999 and 1998.
Operating results for interim periods are not necessarily indicative of
the results for full years. It is suggested that these condensed consolidated
financial statements be read in conjunction with the consolidated financial
statements for the year ended December 31, 1998 and the related notes thereto
included in Form 10-KSB and 10KSB/A as filed with the SEC. It is further
suggested that all comparative information be considered in the context of
certain acquisitions closed on May 14, 1998, which resulted in significant
changes to the scope, focus and method of doing business of the Company and may
diminish the value of the comparisons when analyzing relevant trends.
3
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
------------------- -----------------
(unaudited)
<S> <C> <C>
Current assets:
Cash and cash equivalents............................................... $ 406,380 $ 646,200
Accounts receivable, net of allowance for doubtful
accounts of $506,148 at June 30, 1999 and
$348,984 at December 31, 3,517,657 3,209,633
1998.................................................................
Prepaid expenses and other.............................................. 631,070 122,422
Receivables from affiliates............................................. 818,693 963,700
------------------- -----------------
Total current assets........................................... 5,373,800 4,941,955
Property and equipment, successful efforts method of accounting.............. 71,006,470 70,044,882
Less accumulated depletion, depreciation
and amortization........................................................ (20,100,904) (15,517,656)
------------------- ----------------
50,905,566 54,527,226
Other assets ............................................................... 895,016 447,091
------------------- ----------------
Total assets................................................... $ 57,174,382 $ 59,916,272
=================== ================
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY
JUNE 30, DECEMBER 31,
1999 1998
----------------- ----------------
<S> <C> <C>
Current liabilities:
Accounts payable........................................................ $ 7,637,635 $ 8,993,859
Accounts payable to affiliate, net...................................... 280,034 4,322,548
Revenue distribution payable............................................ 3,043,412 1,996,091
Current portion of long-term debt....................................... 8,070,000 101,236
Accrued and other liabilities........................................... 1,788,122 484,756
----------------- ----------------
Total current liabilities...................................... 20,819,203 15,898,490
Long-term debt .............................................................. 8,350,000 7,500,000
Non-recourse debt ........................................................... 864,000 864,000
Accrued interest on non-recourse debt ....................................... 397,154 331,194
----------------- ----------------
Total liabilities ............................................. 30,430,357 24,593,684
Stockholders' equity:
Common stock:
Class A common stock, $.01 par value; 40,000,000 shares authorized;
15,790,084 outstanding at June 30,
1999 and 15,784,834 outstanding December 31, 1998.................... 157,902 157,849
Additional paid-in capital ............................................. 77,662,386 77,651,602
Accumulated deficit..................................................... (51,076,263) (42,486,863)
----------------- ----------------
Total stockholders' equity..................................... 26,744,025 35,322,588
------------------- ----------------
Total liabilities and stockholders' equity..................... $ 57,174,382 $ 59,916,272
================= ================
</TABLE>
The accompanying notes are an integral part of these financial statements.
4
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30 SIX MONTHS ENDED JUNE 30,
1999 1998 1999 1998
--------------- --------------- -------------- ---------------
<S> <C> <C> <C> <C>
Revenues:
Gas and oil revenues............................ $792,861 $106,361 $1,757,106 $154,864
Realized gain (loss) on commodity transactions.. 7,174 (50,687) 198,023 (98,562)
Unrealized gain on commodity transactions - 138,082 - 87,071
Gain (loss) on sale of assets................... (161,020) 553 110,632 3,428
Operating fees.................................. 89,617 92,469 153,351 99,461
Other revenues.................................. 3,915 78,931 24,437 102,861
--------------- --------------- -------------- ---------------
Total revenues.............................. 732,547 365,709 2,243,549 349,123
--------------- --------------- -------------- ---------------
Costs and expenses:
Lease operating expense......................... 118,617 (15,366) 372,588 54,407
Production taxes................................ 51,441 6,042 115,234 4,952
Transportation and gathering costs.............. - 687 - 1,326
Depletion, depreciation and amortization........ 556,827 84,798 1,175,827 138,366
Amortization of unproved properties............. 1,975,000 - 4,358,000 -
Exploration costs - geological and geophysical.. 610,029 2,805,868 1,355,487 2,793,183
Exploration costs - dry hole.................... 65,278 1,036,541 65,278 1,040,101
Interest expense................................ 185,153 198,676 308,439 217,899
General and administrative expense.............. 1,678,124 1,260,593 3,082,096 1,719,608
--------------- --------------- -------------- ---------------
Total costs and expenses.................... 5,240,469 5,377,839 10,832,949 5,969,842
Loss before provision for income taxes............... (4,507,922) (5,012,130) (8,589,400) (5,620,719)
Benefit (provision) for income taxes................. - - - -
Net loss............................................. (4,507,922) (5,012,130) (8,589,400) (5,620,719)
Cumulative preferred stock dividend.................. - 22,350 - 48,138
--------------- --------------- -------------- ---------------
Net loss applicable to common stockholders........... ($4,507,922) ($5,034,480) ($8,589,400) ($5,668,857)
=============== =============== ============== ===============
Net loss per common and common equivalent share...... ($0.29) ($0.73)(1) ($0.54) ($1.32)(1)
=============== =============== ============== ===============
Weighted average number of common shares
Outstanding (in thousands).................. 15,790 6,876(1) 15,790 4,280(1)
=============== =============== ============== ===============
</TABLE>
(1) After giving effect to the 1:6 reverse stock split effected on May 14, 1998.
The accompanying notes are an integral part of these financial statements.
5
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Six Months Ended June 30,
------------------------------------------
1999 1998
------------------- -----------------
<S> <C> <C>
Cash flows from operating activities:
Net loss...................................................... $ (8,589,400) $ (5,620,719)
Adjustments to reconcile net loss to net cash used in operating
activities:
Depletion, depreciation and amortization ..................... 1,175,827 138,366
Amortization of unproven property............................. 4,358,000 -----
Gain on sale of assets........................................ (110,632) (3,428)
Amortization of financing costs and warrants.................. 37,644 48,505
Unrealized loss on commodity transactions..................... ----- (87,071)
Exploration costs............................................. 65,278 1,040,101
Changes in operating assets and liabilities:
Trade and affiliate receivables........................... (163,017) (1,171,646)
Prepaid expenses and other................................ (508,648) (155,915)
Other assets.............................................. (485,569) (730,201)
Accounts payable.......................................... (1,356,224) 4,017,856
Accounts payable to affiliates............................ (1,342,514) 456,464
Revenue distribution payable.............................. 1,047,321 (3,499)
Accrued and other......................................... 1,369,326 615,941
------------------- ------------------
Net cash used in operating activities......................... (4,502,608) (1,455,246)
------------------- ------------------
Cash flows used in investing activities:
Capital expenditures - gas and oil properties................. (8,009,362) (5,555,970)
Capital expenditures - other property and equipment........... (146,838) (50,236)
Proceeds from sale of assets.................................. 3,589,387 15,995
------------------- ------------------
Net cash used in investing activities..................... (4,566,813) (5,590,211)
------------------- ------------------
Cash flows from financing activities:
Proceeds from issuance of common stock 10,837 -----
Proceeds from issuance of debt................................ 8,820,000 8,300,000
Repayments of long-term debt.................................. (1,236) (683,871)
Preferred stock redeemed...................................... ----- (859,610)
Preferred stock dividends paid................................ ----- (228,654)
------------------- ------------------
Net cash provided by financing activities................. 8,829,601 6,527,865
------------------- ------------------
Net decrease in cash and cash equivalents................. (239,820) (517,592)
Cash and cash equivalents at beginning of period................... 646,200 690,576
------------------- ------------------
Cash and cash equivalents at end of period......................... $ 406,380 $ 172,984
=================== ==================
Supplemental disclosure of cash flow information:
Cash paid for interest........................................ $ 644,643 $ 169,321
=================== ==================
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 gas and oil properties..................... ---- $ 58,864,160
Proxy Costs............................................... ---- 287,173
Assumption of related liabilities......................... ---- 8,146,618
Issuance of 10,106,722 shares of common stock............. ---- 50,430,370
</TABLE>
The accompanying notes are an integral part of these financial statements.
6
<PAGE>
ESENJAY EXPLORATION, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The accompanying unaudited condensed consolidated financial statements
of Esenjay Exploration, Inc. and its subsidiaries and its predecessor Frontier
Natural Gas Corporation (the "Company") have been prepared in accordance with
generally accepted accounting principles for interim financial information.
Accordingly they do not include all of the information and footnotes required
by generally accepted accounting principles for complete financial statements.
Interim results are not necessarily indicative of results for a full year.
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.
Valuation allowances are provided if the net capitalized costs of gas and oil
properties at the field level exceed their realizable values based on
expected future cash flows. Unproved properties are periodically assessed for
impairment and, if necessary, a loss is recognized. The Company recognized no
impairments for the three and six month periods ended June 30, 1999.
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, 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. The total remaining net book value of the
properties acquired pursuant to the Acquisition, which was not transferred to
producing properties and/or amortized, was $22,362,400 and $32,686,300,
respectively, at June 30, 1999 and December 31, 1998.
A summary of all of the Company's significant accounting policies is
presented on pages 39 and 40 of its 1998 Form 10KSB/A filed with the SEC.
Users of financial information are encouraged to refer to the footnotes
contained therein when reviewing interim financial results. There have been
no material changes in the accounting policies followed by the Company during
1999.
The accompanying interim financial statements contain all material
adjustments, which are in the opinion of management, consistent with the
adjustments necessary to present the fairly stated consolidated financial
position, results of operations and cash flows of Esenjay Exploration, Inc.
for the interim period. Certain prior period amounts have been reclassified
to conform with the current period presentation.
7
<PAGE>
2. LONG-TERM DEBT:
Long-term debt consists of the following:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
------------- ---------------
<S> <C> <C>
Note payable repaid in 1999....................................................... $ --- $ 1,236
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest
accrued at 15%................................................................. 864,000 864,000
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 all properties currently owned by the Company...... 8,250,000 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 quarter for five quarters
beginning on May 1, 1999, and reducing to zero on August 1, 2000. Total
available as of June 30, 1999 was $8,070,000. The interest rate is prime plus
4%. The loan is secured by a mortgage on all properties currently owned by
the Company................................................................... 8,070,000 ---
-------------- -----------------
17,284,000 8,465,236
Less current portion.............................................................. 8,070,000 101,236
-------------- -----------------
$ 9,214,000 $ 8,364,000
============== =================
</TABLE>
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 closing of the credit agreement.
Proceeds of the loan primarily supplement working capital. As part of the
credit agreement, the Company is subject to certain covenants and
restrictions, among which are the limitations on additional borrowing, and
sales of significant properties, working capital, cash, and net worth
maintenance requirements and a minimum debt to net worth ratio. In July of
1999 the covenants were amended to decrease the Tangible Net Worth
requirement from a minimum of $45,000,000 to a minimum of $25,000,000. The
covenants regarding financial condition of Company are as follows:
<TABLE>
<S> <C>
Tangible Net Worth............................ $25,000,000 + 50% of Consolidated Net Income + 100% of net
proceeds received from sale of any Non-Redeemable Stock
Current Ratio................................. 1.1:1.0
Debt to Capitalization........................ 0.5:1.0
Interest Coverage Ratio ...................... 1.0:1.0 -1st quarter 1999; 3.0:1.0 - 2nd quarter 1999 and any
consecutive quarters after June 30, 1999
</TABLE>
8
<PAGE>
As of June 30, 1999, the Company's current ratio was 0.4411 and the
Company's interest coverage ratio was (2.5790) to 1, both of which were,
therefore, in noncompliance. Although the Company brought in significant cash
via the sale of project interests in the quarter, its significant capital
expenditures in the quarter in the form of drilling costs caused it to be in
non-compliance at June 30, 1999. B of A has waived said noncompliance at June
30, 1999. The Company believes it has improved its current ratio and its
interest coverage ratio since June 30, 1999 significantly. Although the
Company believes it can be in compliance with both of these covenants
throughout the remainder of 1999, there can be no assurance that it will be
in compliance. As a result it is possible that additional waivers may be
needed in the future. In the event B of A did not grant such waivers, if
needed, the Company would be in noncompliance of the covenants and would seek
alternative financing arrangements.
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 $5,323 at June
30, 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.
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 $8,070,000 outstanding on said facility as of
June 30, 1999,which represented the total amount then available. The commitment
reduces by $930,000 per quarter until it reduces to zero on August 1, 2000.
Principal outstanding cannot exceed the commitment amount at any time. Duke is
paid interest at a rate of prime plus 4%. It also received a right to gather and
process, at fair market value, gas and condensate from a designated area of
interest, and a net revenue interest in certain of the Company's future drilling
activities not to exceed 0.49% of the Company's net interest. Proceeds primarily
supplement exploration costs.
On January 28, 1999, the Company, B of A, and Duke entered into an
intercreditor agreement which governs the collateral which is used to secure the
credit facility with B of A and the credit facility with Duke. Tranche A of the
B of A credit facility is secured by a first mortgage on most of the Company's
proven properties. Collateral securing amounts outstanding under both the Duke
credit facility and Tranche B of the B of A facility is primarily comprised of
mortgages taken on a significant proportion of the Exploration Projects of the
Company which have not been developed. At such time as drilling is conducted on
the Exploration Projects and proven reserves are discovered, the Company has a
right to seek increases in the available amount to be drawn under Tranche A of
its credit facility with B of A. In the event B of A agrees to increase the
amounts available pursuant to Tranche A, then, subject to Duke's consent,
security interests in proven reserves would be used as additional primary
collateral on Tranche A loans from B of A supporting the borrowing availability
increases.
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
provides for the merger of 3DX into the Company. The Boards of both companies
have approved the transaction, and closing of the merger is conditioned upon
approval from the shareholders of both companies and satisfaction of certain
other conditions set forth in the Plan and Agreement of Merger.
The terms of the merger provide for 3DX shareholders to receive, at
their election, either (i) the issuance of one share of common stock of the
Company for 3.25 shares of 3DX common stock; or (ii) the issuance of a new
convertible preferred stock of the Company at a ratio of one share of
convertible preferred stock for each 2.75 shares of 3DX common stock. The
preferred stock is limited to 50% of the total 3DX shares converted and may be
redeemed at the Company's sole option during the first twelve months after the
merger at $1.925 per share. If not redeemed during the first year, the preferred
will automatically convert into one share of common stock of the Company if the
average closing price of the common is greater than $1.875 during the twelfth
month after closing. If the common is less than $1.875, the preferred holder has
the right for one month to "put" the shares to the Company, which will then have
the option, at the sole election of the Company, 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.
Any share of convertible preferred stock not redeemed by the Company or tendered
by the holder, as set forth above, by the fourteenth month after the merger will
automatically convert into one share of common stock of the Company. The Company
currently has 15,823,271 common shares outstanding and 3DX currently has
9,691,761 shares outstanding.
9
<PAGE>
3DX Technologies Inc. is a Houston-based exploration and production
company whose strategic business focus has been 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, if consummated, the Company will offer employment to approximately five
members of the reservoir engineering and geophysical staff of 3DX, increase its
gas and oil reserves, its monthly gas and oil revenues, and expand its ownership
of 3D seismic data and projects.
3. RELATED PARTY TRANSACTIONS
The Company's outstanding accounts receivable from employees and
affiliates of the Company at June 30, 1999 and December 31,1998 was $818,693
and $963,700, respectively. The June 30, 1999 and December 31, 1998
receivables include approximately $47,787 from an affiliated partnership for
which the Company serves as the managing general partner. In addition, the
June 30, 1999 balance includes a net $733,732 receivable from EPC primarily
related to joint interest billings. At June 30, 1999 the Company had a
remaining net account payable to Aspect in the amount of $280,034. In June
1999, the Company closed a sale to Aspect of 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 interests in the West Beaumont Project area for
an aggregate of approximately $2,600,000. Proceeds from the sale were used to
help settle amounts due Aspect.
4. COMMITMENTS AND CONTINGENCIES
The Company markets its natural gas through monthly spot sales. Because
sales made under spot sales contracts result in fluctuating revenues to the
Company depending upon the market price of gas, the Company may enter into
various hedging agreements to minimize the fluctuations and the effect of price
declines or swings. During January 1999, the Company completed performance on a
1996 swap agreement on approximately 1,040 MMBtu's per day of Mid-Continent
natural gas production for $1.566 per MMBtu for the period beginning April 1,
1996 and ending January 31, 1999.
In October of 1998, the Company entered into two swap agreements, one
for 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.14 per
MMBtu for the period beginning November 1998 and ending in October 1999, and the
second one for 700 MMBtu's per day of its Gulf Coast natural gas production for
$2.13 per MMBtu for the period beginning November 1998 and ending in October
1999. Both of these swap agreements were supplemented in December 1998 when the
Company entered into additional swap agreements, one of which was for 4,000
MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for
the period beginning November 1999 and ending in October 2000, and the second
one was for 700 MMBtu's per day of its Gulf Coast natural gas production for
$2.07 per MMBtu for the period beginning November 1999 and ending in October
2000. As a result of the foregoing transactions, the Company has 4,700 MMBtu's
per day of its Gulf Coast natural gas production hedged through October 2000.
5. NEW 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 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis reviews Esenjay Exploration,
Inc.'s and/or its predecessor Frontier Natural Gas Corporation's operations for
the three and six month periods ended June 30, 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
10
<PAGE>
uncertain results of 3-D seismic surveys, 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 members of
EPC's management that joined the Company after consummation of the acquisitions
significantly enhanced the Company's management team.
In connection with the Acquisitions, an affiliate of Enron Corp.
exercised an option to exchange $3.8 million of debt Aspect owed to such Enron
affiliate for 675,000 shares of the Company's Common Stock that would otherwise
have been issued to Aspect in the Acquisitions, at an effective conversion rate
of $5.63 per share. As a result of the Acquisitions and this exchange and the
secondary public offering effective in July of 1998, EPC, Aspect and the Enron
affiliate own approximately 33%, 28% and 4%, respectively, of the Company's
Common Stock.
On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering the
Company had 15,762,723 shares outstanding.
11
<PAGE>
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 believes
it is positioned for a period of significant exploration activity on its
technology enhanced projects. Many of the projects have reached the drilling
stage. In many instances the requisite process of geological and/or engineering
analysis, followed by acreage acquisition of leasehold rights and seismic
permitting, and 3-D seismic field data acquisition, then processing of the data
and finally its interpretation, 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 second quarter costs due to consultants fees,
employment severance packages, and new systems implementation. However, as a
result, the Company expects certain general and administrative cost decreases in
the third and fourth quarters and management and operational efficiencies to
increase.
In the first quarter of 1999, the Company participated in six new
wells. In the second quarter of 1999, it participated in four additional new
wells and since the end of the second quarter, the Company has participated
in six additional new wells. Of the total wells drilled in 1999 two were
producing as of June 30, 1999, four more are now producing, five are
scheduled to commence production upon completion of pipeline connections, two
were dry holes and three were drilling. Based upon estimated sustainable flow
rates, the 1999 wells are anticipated to increase the Company's net daily
production to approximately 600 barrels of oil per day and 14,000,000 cubic
feet of natural gas per day.
The Company entered 1999 having gone from nominal second quarter
1998 gas and oil revenues of approximately $35,000 per month and large
operating cash flow deficits to a company which averaged $325,000 per month
in net oil and gas revenues and associated hedging revenues from commodity
transactions in the first six months of 1999. This number is expected to
increase significantly as the wells drilled in 1999 continue to come on line.
This should allow 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 and beyond. In
addition, the Company has closed the sale of additional project interests for
a total price of $4,800,000 since June 30, 1999, which sales resulted in
increased availability of cash resources and enhanced working capital. (See
"Liquidity and Capital Resources").
The Company will look to a variety of sources to fund its continuing
capital expenditures budget, including it's credit facilities and sales of
promoted project interests to industry partners, as it seeks to maximize its
interests and manage its risks while aggressively pursuing its exploration
projects. (see "Liquidity and Capital Resources").
On May 12, 1999, the Company announced that on May 11, 1999 it had
entered into a Plan and Agreement of Merger with 3DX Technologies, Inc. ("3DX")
which provides for the merger of 3DX into the Company. The plan is subject to
the approval of shareholders of both companies, which shareholders meetings are
expected to be held in approximately 25 to 30 days. (See Part II, Item 5 "Other
Information").
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, and which were comprised primarily of interests in unproven 3-D
seismic based projects, recorded in May of 1998 at an
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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. Hence significant non-cash charges will likely
depress reported earnings of the Company over the next several years, but
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 is exposed to the risk that the Year 2000 issue could cause
system failures or miscalculations causing disruptions of operations, including,
among other things, a temporary inability to process transactions, send joint
interest billings, or engage in similar normal business activities. During 1998,
the Company undertook a corporate-wide initiative designed to assess the impact
of the Year 2000 issue on software and hardware utilized in the Company's
operations.
The Company's initiative is to be conducted in these phases:
assessment, implementation and testing. During the assessment phase, the Company
completed a comprehensive inventory of all "mission critical" systems and
equipment. Many of the Company's systems include hardware and packaged software
purchased from large vendors who have represented that these systems are already
Year 2000 compliant.
The Company relies on other producers and transmission companies to
conduct its basic operations. Should any third party with which the Company has
a material relationship fail, the impact could impair the Company's ability to
perform its basic operation. Examples of such changes are an inability to
transport production to market or an inability to continue drilling activities.
As part of the Company's assessment phase, the Company will address the most
reasonably likely worst-case scenarios and potential costs.
The majority of the Company's technical applications are not date
sensitive. Of those applications that are date sensitive, most have recently
been, or are currently being, upgraded. However, if such modifications are not
adequate or do not operate properly, the Year 2000 issue could have a material
impact on the Company. The Company intends to complete the testing of Year 2000
modifications during the third quarter of 1999. The Company has not established
a contingency plan but is formulating one to address unavoidable risks,
including those discussed above. The Company expects to have the contingency
plan formulated by September 30, 1999.
The Company's efforts with respect to the Year 2000 issue have been
handled internally by management and other Company personnel. Costs of
developing and carrying out this initiative are being funded from the Company's
operations and have not represented a material expense to the Company. The
Company has completed most of its assessment and currently believes that the
costs of addressing the Year 2000 issue should not be significant and should not
have a material adverse impact on the Company's financial condition.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company during the periods indicated:
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
1999 1998 1999 1998
------- ------ --------- ------
<S> <C> <C> <C> <C>
PRODUCTION:
Gas (MMcf).......................... 499.6 35.6 1,026.3 56.2
Oil and condensate (MBbls).......... 10.4 2.2 13.7 3.4
Total equivalent (Mmcfe)............ 562.1 48.8 1,108.5 76.6
AVERAGE SALES PRICE:
Gas (per Mcf)....................... $ 2.08 $ 2.15 $ 1.87 $ 2.21
Oil and condensate (per Bbl)........ $ 15.87 $12.50 $ 13.63 $13.00
AVERAGE EXPENSES (PER MCFE):
Lease operating(1).................. $ 0.21 $(0.31) $ 0.34 $ 0.71
Depletion of oil and gas properties: $ 0.99 $ 1.74 $ 1.06 $ 1.81
</TABLE>
(1) Includes all direct expenses of operating the Company's properties,
as well as production and ad valorem taxes.
THREE MONTHS ENDED JUNE 30, 1999 COMPARED WITH THREE MONTHS ENDED JUNE 30, 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, the comparisons may be of more limited value when
analyzing relevant trends.
REVENUE. Total revenues increased 100.31% from $365,709 for the quarter
ended June 30, 1998 to $732,547 for the quarter ended June 30, 1999. This is
primarily attributed to factors described below.
Total gas and oil revenues increased 645.44% from $106,361 to $792,861.
The increase was attributed mainly to revenues from wells placed in production
in late 1998 and early 1999. The Company realized a loss from various commodity
transactions totaling $50,687 for the second quarter of 1998. These loses were
attributed to various
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<PAGE>
transactions in which the Company hedged future gas delivery obligations as a
requirement of its bank loan facility. The Company recognized net gains of
$7,174 for the second quarter of 1999. This was due to average hedging prices
received by the Company exceeding the spot market prices during the period.
The Company accrued unrealized gains on commodity transactions of $138,082
for the quarter ended June 30, 1998. In 1999, production volumes have
exceeded hedged volumes and, as a result, unrealized gains or losses are not
realized. Operating fees decreased slightly from $92,469 for the quarter
ended June 30, 1998 to $89,617 for the same period June 30, 1999. There was a
decrease in gain (loss) on sale of assets of $161,573 from $553 for the quarter
ended June 30, 1998 to a recorded loss of $161,020 reported for the same
period ending June 30, 1999. This decrease was due to recorded losses on
various property sales. Other revenues decreased from $78,931 for the quarter
ended June 30, 1998 to $3,915 for the quarter ended June 30, 1999. This was
largely attributed to reduced interest income from trade and affiliate
receivables.
COSTS AND EXPENSES. Total costs and expenses of the Company decreased
2.55% from $5,377,839 for the quarter ended June 30, 1998 to $5,240,469 for the
same period ending June 30, 1999. This decrease in costs and expenses was
attributed to a combination of expenditures relating to staffing, activity
volumes, departmental reorganization and systems. Increases in lease operations
expense, production taxes, depletion, depreciation and amortization and general
and administrative costs were partially offset by reductions in transportation
and gathering costs, exploration costs, geological and geophysical, exploration
costs, dry hole costs and interest expense.
LEASE OPERATING EXPENSE increased 871.94% from ($15,366) for the second
quarter of 1998 to $118,617 for the second quarter of 1999. The increase in
lease operating costs was attributed to operational costs for the Company's
wells placed into production in late 1998 and early 1999.
PRODUCTION TAXES increased 751.39% from $6,042 for the second quarter
of 1998 to $51,441 for the second quarter of 1999. The increase in production
taxes was attributed to revenues of wells placed in production in late 1998 and
early 1999.
TRANSPORTATION AND GATHERING COSTS decreased 100% from $687 for the
second quarter of 1998 as compared to none for the second quarter of 1999. The
decrease in transportation and gathering costs was entirely attributed to the
ceased production of the Company's well in Mobile Bay.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") increased 556.65%
from $84,798 for the second quarter of 1998 to $556,827 for the second quarter
of 1999. The increase to DD&A was attributed to wells placed in production in
late 1998 and early 1999. Of the total, $157,810 was associated with wells
placed in production during the second quarter of 1999.
AMORTIZATION OF UNPROVED PROPERTIES was $1,975,000 for the second
quarter of 1999 (none in 1998). The Company will amortize the undeveloped and
unevaluated value of the properties acquired pursuant to the Acquisitions over a
period not to exceed forty-eight months. (See "Overview - Successful Efforts
Accounting and Related Matters").
EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL was $610,029 for the
second quarter of 1999 and $2,805,868 for the second quarter of 1998. These
exploration costs reflect costs of topographical, geological and geophysical
studies and include the expenses of geologists, geophysical crews and other
costs of acquiring and analyzing 3-D seismic data. The Company's technology
enhanced exploration program on the Exploration Projects has required the
acquisition and interpretations of substantial quantities of such data. The
Company considers 3-D seismic data a valuable asset; however, its successful
efforts accounting method requires such costs to be expensed for accounting
purposes. Also included in exploration costs - geological and geophysical are
$39,320 in delay rental costs for the second quarter of 1999, as compared to
$17,768 for the first quarter of 1998.
EXPLORATION COSTS - DRY HOLE decreased 93.7% from $1,036,541 for the
second quarter of 1998 to $65,278 for the second quarter of 1999.
INTEREST EXPENSE decreased 6.81% from $198,676 for the second quarter
of 1998 to $185,153 for the same period 1999 due to increased loans outstanding.
The Company capitalized a large portion of its interest associated with its
on-going projects, of which capitalized amounts totaled $240,137 for the second
quarter of 1999 and $82,117 for the second quarter of 1998.
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<PAGE>
GENERAL AND ADMINISTRATIVE EXPENSES increased 33.12% from $1,260,593
for the second quarter of 1998 to $1,678,124 for the second quarter of 1999.
This was primarily attributable to increases in operational expenses incurred
after May 14, 1998, the effective date of the Asset Acquisition Agreement
between Aspect and EPC, after which time the scope of the Company's activities
increased significantly. Approximately $227,511 in the second quarter of 1999
were costs associated with the Company's departmental reorganization,
information systems conversions and implementation, which will primarily be
non-recurring charges.
NET LOSS PER COMMON SHARE decreased from a net loss of $0.73 per share
for the second quarter of 1998 to a net loss of $0.29 per share for the second
quarter of 1999. Due to the factors enumerated above, there was a decrease in
net loss applicable to common stockholders of $504,208 from the second quarter
of 1998 as compared to the second quarter of 1999. Approximately 15,790,000
weighted average common equivalent shares were outstanding at June 30, 1999 as
compared with approximately 6,876,000 at June 30, 1998, which further influenced
the decrease in net loss per share in 1999.
SIX MONTHS ENDED JUNE 30, 1999 COMPARED WITH SIX MONTH ENDED JUNE 30, 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 method of doing business of the
Company. As a result, the comparisons may be of more limited value when
analyzing relevant trends.
REVENUE. Total revenues increased 542.62% from $349,123 for the six
months ended June 30, 1998 to $2,243,549 for the six months ended June 30, 1999,
due to the factors listed below.
Total gas and oil revenues increased 1034.61% from $154,864 for the six
months ended June 30, 1998 to $1,757,106 for the six months ended June 30, 1999.
The increase in gas and oil revenues was attributed to wells placed in
production late 1998 and early 1999. There was an increase in gain on sale of
assets of $107,204 from $3,428 for the six months ended June 30, 1998 to
$110,632 for the six months ended June 30, 1999. The increase was due to the
closing of various project interest sales to third parties, which resulted in an
aggregate loss for the period. Increases in operations from both exploratory and
developmental drilling have resulted in the increase of operating fees of 54.18%
from $99,461 for the six months ended June 30, 1998 to $153,351 for the six
months ended June 30, 1999. The Company realized a loss from various commodity
transactions of $98,562 for the six months ended June 30, 1998. These losses
were attributed to various transactions in which the Company hedged future gas
delivery obligations as a requirement of its bank loan facility. The Company
recognized net gains of $198,023 for the six months ended June 30, 1999. This
was due to the Company's average hedge prices exceeding the spot market prices
during the period. The Company recognized an unrealized gain on commodity
transactions for the six months ended June 30, 1998 of $87,071 as compared to
none for the six months ended June 30, 1999. This was due to the fact that 1999
oil and gas production volumes were greater than hedge volumes and as a result
the Company no longer recognizes unrealized gains or losses in its hedge
accounts. In addition to the foregoing, the Company had other revenues of
$102,861 for the six months ended June 30, 1998 as compared to $24,437 for the
six months ended June 30, 1999. This decrease was primarily attributed to the
reduction of interest income from trade and affiliate receivables of $60,861.
COSTS AND EXPENSES. Total costs and expenses of the Company increased
81.46% from $5,969,842 for the six months ended June 30, 1998 to $10,832,949 for
the six months ended June 30, 1999. The increases primarily relate to changes in
scope, focus and method of doing business, which occurred upon closing of the
Acquisition Agreement among the Company, EPC and Aspect. As a result, staffing,
departmental reorganization and activity volumes increased dramatically. The
increase in 3-D seismic, geological and geophysical work was intended to lead to
increased risk controlled drilling and ultimately increased gas and oil revenues
and production. The increase in costs and expenses was primarily attributable to
a combination of increases in amortization of unproved properties, general and
administrative costs, depletion, depreciation and amortization, lease operation
expenses, interest expense and production taxes. Partially offsetting the
foregoing increases were decreases in exploration costs - geological and
geophysical, exploration costs - dry hole and transportation and gathering
costs.
AMORTIZATION OF UNPROVED PROPERTIES was $4,358,000 for the six months
ended June 30, 1999 (none in 1998). The Company will amortize the undeveloped
and unevaluated value of the properties acquired pursuant to the
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<PAGE>
Acquisition over a period not to exceed forty-eight months. (See "Overview -
Successful Efforts Accounting and Related Matters").
GENERAL AND ADMINISTRATIVE EXPENSES increased 79.23% from $1,719,608
for the six months ended June 30, 1998 to $3,082,096 for the six months ended
June 30, 1999. This was primarily due to increases in operational expenses
incurred after May 14, 1998, the effective date of the Acquisition Agreement
with Aspect and EPC. After such time the scope of the Company's activities
increased significantly. Approximately $261,323 in the six months ended June 30,
1999 costs were associated with departmental reorganization, information systems
conversions and implementation.
DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 749.79%
from $138,366 for the six months ended June 30, 1998 to $1,175,827 for the six
months ended June 30, 1999. The increase in DD&A was primarily attributed to
wells placed in production during late 1998 and early 1999.
LEASE OPERATING EXPENSES increased 584.82% from $54,407 for the six
months ended June 30, 1998 to $372,588 for the six months ended June 30, 1999.
The increase in lease operating expenses relates primarily to operational cost
for the Company's wells placed in production during late 1998 and early 1999. In
addition, the Company incurred $149,067 of costs associated with compressor
installations, and road repairs.
INTEREST EXPENSE increased 41.55% from $217,899 for the six months
ended June 30, 1998 to $308,439 for the six months ended June 30, 1999. The
increase in interest expense was attributable to a credit facility with Duke
Energy Financial Services, Inc. closed in February 1999 and an increase in
borrowings pursuant to its credit facility with Bank of America NT&SA in October
1998. The Company capitalizes a large portion of its interest associated with
on-going projects, of which capitalized amounts totaled $574,119 for the six
months ended June 30, 1999 and $161,219 for the six months ended June 30, 1998.
PRODUCTION TAXES increased 2,227.02% for $4,952 for the six months
ended June 30, 1998 to $115,234 for the six months ended June 30, 1999. This
increase in production taxes was attributed to revenues of wells placed in
production late 1998 and early 1999.
EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL decreased 51.47% from
$2,793,183 for the six months ended June 30, 1998 to $1,355,487 for the six
months ended June 30, 1999. The decrease resulted from a decreased volume of new
3-D data acquisitions primarily in the second quarter of 1999. These exploration
costs reflect costs of topographical, geological and geophysical studies and
include the expenses of geologists, geophysical crews and other costs of
acquiring and analyzing 3-D seismic data. The Company's technology enhanced
exploration program on the Exploration Projects has required the acquisition and
interpretations of substantial quantities of such data. The Company considers
3-D seismic data a valuable asset; however, its successful efforts accounting
method requires such costs to be expensed for accounting purposes. Included in
exploration costs at $71,009 is delay rental costs for the six months ended June
30, 1999, as compared to $17,765 for the six months ended June 30, 1998.
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 provided by/(used in)
operating activities would have been ($2,147,121) and $1,337,937 for the six
months ended June 30, 1999 and 1998, respectively, if the geological and
geophysical add back were permitted. The cash flow used in investing
activities would have been $6,922,300 and $8,383,394 for the six months ended
June 30, 1999 and 1998, respectively, if the geological and geophysical costs
were permitted to be included.
EXPLORATION COSTS - DRY HOLE decreased 93.72% from $1,040,101 for the
six months ended June 30, 1998 to $65,278 for the six months ended June 30,
1999. The reduction can be attributed to the Company's high percentage of
drilling success from late 1998 continuing through early 1999.
TRANSPORTATION AND GATHERING COSTS decreased 100% from $1,326 for the
six months ended June 30, 1998 as compared to none for the six months ended June
30, 1999. The decrease in transportation and gathering costs was entirely
attributed to ceased production of the Company's wells in Mobile Bay.
NET LOSS PER COMMON SHARE decreased from a net loss of $1.32 per share
for the second quarter of 1998 to a net loss of $0.54 per share for the second
quarter of 1999. Due to the factors discussed above, there was a decrease in
net loss applicable to common stockholders of $2,968,681 from the second quarter
of 1998 as compared to the second quarter of 1999. Approximately 15,790,000
weighted average common equivalent shares were outstanding at June 30, 1999 as
compared with approximately 4,280,000 at June 30, 1998, which further influenced
the decrease in net loss per share in 1999.
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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, as well as its other prospects.
While management believes said projects represent the most promising
prospects in the Company's history, and the wells drilled on projects acquired
pursuant to the Acquisitions in 1998 and 1999 continue to substantially increase
the Company's revenues, the capital expenditures planned in the remainder of
1999 and into 2000 will continue to require substantial outlays of capital to
explore, develop and produce. Drilling results for 1998 have in fact resulted in
substantial revenue increases. Drilling results in the first seven months of
1999 should result in rapidly expanding revenues throughout the remainder of
1999 as the wells come on line. The Company anticipates certain general and
administrative cost decreases in the third and fourth quarters due to personnel
and systems changes being implemented which are intended to increase efficiency
and/or reduce costs. In the event it completes the acquisition of 3DX
Technologies, Inc., certain of the planned savings would be offset by staff
additions pursuant to the merger, but which cost additions would be more than
offset by revenue increases from producing properties acquired in the merger.
However, because of the Company's expanded 1999 drilling budget, capital from
sources other than cash flow from operations will continue to be required for
funding planned exploration activities. The Company's 1999 budget continues to
include the sales of certain project interests to industry partners, which have
not materialized in the first half of 1999 as rapidly as planned. The
Company's drilling program may have to be reduced if the Company does not
execute such sales in the third and fourth quarter of 1999.
LIQUIDITY AND CAPITAL RESOURCES
The Company incurred approximately $11,000,000 in drilling,
completion, land and seismic costs net to its account in the first six months
of 1999. It has currently budgeted in excess of $10,000,000 in such costs in
the third and fourth quarters of 1999, and plans similar budgets for the
first half of 2000. These budgeted amounts are based upon exploration
opportunities and will be adjusted based upon available capital. The
Company's sources of financing include borrowing capacity under its existing
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, which
did not materialize as rapidly as planned in the first half of 1999. The
Company expects said sales will continue to be consummated but has delayed the
drilling of certain wells pending such sales. The Company's drilling program
may have to be reduced if the Company does not execute such sales in the
third quarter of 1999.
The Company entered 1999 having gone from nominal second quarter
1998 gas and oil production of approximately $35,000 per month and large
operating cash flow deficits to a company which averaged $325,000 per month
in oil and gas revenues and realized revenue from hedges on production in the
first half of 1999, most of which is attributable to wells which commenced
production in September and throughout the fourth quarter of 1998. Gas and
oil production is expected to increase as new gas and oil production from
wells drilled in 1999 continue to come on line. Of the total wells drilled in
1999 two were producing as of June 30, 1999, four more are now producing,
five are scheduled to commence production upon completion of pipeline
connections, two were dry holes and three were drilling. Based upon estimated
sustainable flow rates, the 1999 wells are anticipated to increase the
Company's net daily production to approximately 600 barrels of oil per day
and 14,000,000 cubic feet of natural gas per day. This represents an increase
from the 150 barrels of oil per day and 4,250,000 cubic feet of natural gas
per day being produced at the end of the second quarter of 1999. Additional
drilling success in 1999 is expected to continue the trend of rapid
increases. This should allow the Company to achieve steadily increasing
operating cash flow throughout the year (prior to capital expenditures and
new 3-D seismic data acquisition costs, which costs the successful efforts
accounting method utilized by the Company mandate to be expensed rather than
capitalized).
In the quarter ended June 30, 1999, the Company closed two
significant sales of project interests for a total of approximately
$3,900,000 and contracted for a third sale for $4,800,000, which closed in
early August. The two transactions which closed in the second quarter include
a sale to Helmerich & Payne, Inc. ("H&P") and a sale to Aspect. The Company
closed a sale to H&P of its undeveloped property interests in the Big
Hill/Stowell project area and its interests in a project area called Gill
East for $1,300,000. It has also closed a sale to Aspect of 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 an aggregate of approximately $2,700,000. 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
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<PAGE>
independent fairness opinion which management obtained. The third sale, which
was closed in the third quarter and therefore not reflected on the June 30,
1999 financial statements, was a sale to H&P of (i) a 20.8% interest in the
Lovells Lake Project, a project in which the Company retains a 12.5%
interest, and (ii) the Company's entire 33.3% interest in the Bauer Ranch
Project, and (iii) the Company's interest in deep rights in the Gillock
Project. In the Gillock Project, the deep rights sold were those rights below
the Nodosaria sands, and the Company retained its rights in prospects at and
above the Nodosaria sands. H&P also acquired rights from the Company in three
areas not yet evaluated by the Company with 3-D seismic data.
On October 23, 1998, the Company amended and restated its credit
agreement dated January 3, 1996 with B of A. The amended agreement is in a total
amount of $20,000,000 and provided for an immediate borrowing base of up to
$9,000,000. The Company had drawn $8,250,000 pursuant to the B of A loan
facility as of June 30, 1999 and August 10, 1999. The loan is in two tranches.
Tranche A is a revolving facility with no required principal payments for two
years after which it converts into a thirty-six month term loan. Tranche B is
payable in interest only until maturity in eighteen months. Both loans are at a
varied interest rate utilizing either the B of A's Alternate Reference Rate
(Alternate Reference Rate is the greater of (i) B of A's Reference Rate and (ii)
the Federal Funds effective rate plus 0.50%) or the London Interbank rate plus
2% for Tranche A and 4% for Tranche B. All undrawn funds will be available for
future drilling activities of the Company, subject to the approval of the bank.
The Tranche A loan is secured by a mortgage on most proven properties currently
owned by the Company. In addition, certain mortgages on the Company's
exploration project inventory secure Tranche B of the credit facility with B of
A as well as the entire credit facility with Duke discussed below. All such
shared collateral is governed by an intercreditor agreement between B of A and
Duke in which B of A serves as the collateral agent. In addition to the
foregoing, B of A received a 2.0% overriding royalty interest, proportionately
reduced to the Company's net interest, in the properties classified as proven as
of the date of closing and received a five year warrant to purchase 95,000
shares of common stock at a price equal to the average daily closing price of
the Company's common stock for the thirty days prior to closing of the credit
agreement. The credit agreement does not provide for any additional overriding
interests in favor of B of A. Proceeds of the loan primarily supplement working
capital and exploration costs. The Company expects further increases as recently
drilled wells are engineered and come on line.
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 pursuant to a decreasing facility. The commitment reduces by
$930,000 per quarter and reduces to zero on August 1, 2000. The Company has
fully drawn the facility and has $8,070,000 and $7,140,000 on said facility
outstanding as of June 30, 1999 and August 10, 1999, respectively. Principal
outstanding cannot exceed the commitment amount at any time. Duke is paid
interest at a rate of prime plus 4%. It also received a right to gather and
process, at fair market value, gas and condensate from a designated area of
interest, and a net revenue interest in certain of the Company's future drilling
activities not to exceed 0.49% of the Company's net interest. Proceeds primarily
supplement exploration costs.
On January 28, 1999, the Company, B of A, and Duke entered into an
intercreditor agreement which governs the collateral which is used to secure the
credit facility with B of A and the credit facility with Duke. Tranche A of the
B of A credit facility is secured by a first mortgage on most of the Company's
proven properties. Collateral securing amounts outstanding under both the Duke
credit facility and Tranche B of the B of A facility is primarily comprised of
mortgages taken on a significant proportion of the Exploration Projects of the
Company which have not been developed. At such time as drilling is conducted on
the Exploration Projects and proven reserves are discovered, the Company has a
right to seek increases in the available amount to be drawn under Tranche A of
its credit facility with B of A. In the event B of A agrees to increase the
amounts available pursuant to Tranche A, then, subject to Duke's consent,
security interests in proven reserves would be used as additional primary
collateral on Tranche A loans from B of A supporting the borrowing availability
increases.
At June 30, 1999 the Company's tangible net worth as calculated
pursuant to the B of A Credit Agreement was $26,744,025. Recognizing that the
covenant as initially established did not give adequate consideration to the
effects of the Company's successful efforts method of accounting on the future
book value of its properties, in particular the accounting treatment that the
Company has adopted, which requires the amortization over a period not to exceed
forty-eight months of a substantial portion of the property values recorded
pursuant to the Acquisitions, B of A and the Company have amended the credit
agreement to reduce the tangible net worth requirement to $25,000,000. Further,
as of June 30, 1999, the Company's current ratio was 0.4411 and the Company's
interest coverage ratio was (2.5790) to 1, both of which were, therefore, in
noncompliance. B of A has waived said
18
<PAGE>
noncompliance at June 30, 1999. The Company believes it has improved its
current ratio and its interest coverage ratio since June 30, 1999
significantly. Although the Company believes it can be in compliance with
both of these covenants throughout the remainder of 1999, there can be no
assurance that it will be in compliance. As a result it is possible that
additional waivers may be needed in the future. In the event B of A did not
grant such waivers, if needed, the Company would be in noncompliance of the
covenants and would seek alternative financing arrangements.
The Company will require additional sources of capital to fund its
exploration budget over the remainder of 1999 and the first half of 2000. It
anticipates substantial growth of its credit facility with B of A as proven
reserves of gas and oil are added by its exploration program. It also plans to
continue to sell promoted interests in certain of its Exploration Projects to
fund its exploration program over the next 12 months. In the second half of
1999, its capital expenditures budget will be significantly dependent upon sales
of additional interests in the Exploration Projects. Said sales have not
materialized as rapidly as expected and the Company will delay the drilling of
certain wells.
The Company historically has addressed its long-term liquidity needs
through the issuance of debt and equity securities, through bank credit and
other credit facilities and with cash provided by operating activities. Its
major obligations at August 10, 1999, consisted principally of (i) servicing
loans under the credit facilities with B of A and with Duke and other loans,
(ii) funding of the Company's exploration activities, and (iii) funding of the
day-to-day operating costs.
Many of the factors that may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control, including,
but not limited to, oil and natural gas prices, governmental actions and taxes,
the availability and attractiveness of financing and its operational results.
The Company continues to examine alternative sources of long-term capital,
including the acquisition of a company with producing properties for common
stock or other equity securities, including bank borrowings, the issuance of
debt instruments, the sale of common stock or other equity securities, the
issuance of net profits interests, sales of promoted interests in its
Exploration Projects, and various forms of joint venture financing. In addition,
the prices the Company receives for its future oil and natural gas production
and the level of the Company's production will have a significant impact on
future operating cash flows.
In order to minimize the pricing risk associated with oil and gas
sales, the Company entered into hedging transactions aggregating a twenty-four
month period with Bank of America's Financial Engineering and Risk Management
Group. The hedging instruments called for the delivery of 4,700 MMBtu per day at
prices net to the wellhead, which range from $2.07 to $2.14 per MMBtu for the
period November 1, 1998 through October 31, 2000.
PENDING ACQUISITION OF 3DX TECHNOLOGIES, INC. The Company and 3DX
Technologies, Inc. ("3DX") have previously announced entering into a Plan and
Agreement of Merger pursuant to which the Company would acquire 100% of the
issued and outstanding capital stock of 3DX and merge 3DX into itself. The
transaction is currently pending shareholder approval of both companies. Subject
to clearance by the United States Securities and Exchange Commission of a Form
S-4 proxy/registration statement, such shareholders meetings are anticipated to
be held in approximately 25 to 30 days. Consummation of this acquisition would
likely result in increased oil and gas revenues in the second half of 1999, and
an increase in the Company's Tranche A borrowing base with B of A due to
additional producing oil and gas properties. This would increase cash available
to fund drilling activities but would not eliminate the need to find additional
capital to fully fund planned drilling.
WORKING CAPITAL. At June 30, 1999, the Company had a cash balance of
$406,380 and a working capital deficit of $15,445,403. In addition to
availability of unused portions of its increased credit facility with B of A and
pending additional availability from its credit facility with B of A, the use of
which facility could enhance working capital, the Company entered into the
previously referenced agreement to sell additional project interests for
$4,800,000 to H&P which closed in August 1999. Such cash resources serve to
substantially improve working capital. The Company also expects working capital
to be increased due to cash and long term debt facility increases, available if
the pending acquisition of 3DX Technologies, Inc. is closed in September, and
through the sale of additional project interests to industry partners in 1999
for cash. Gas and oil revenues and associated hedging revenues from commodity
transactions from wells which went into production in 1998 are anticipated to
generate
19
<PAGE>
revenues which will exceed ongoing cash costs of operations (prior to capital
expenditures and the cost of new 3-D seismic data acquisitions) in the second
half of 1999 and beyond, which can also enhance the Company's working capital.
Upon the closing of the credit facilities with B of A, the sale of
certain promoted interests in exploration projects, and receipt of the Duke
credit commitment, the Company increased its exploration activities in the
first half of 1999. In order to fund planned drilling and completion costs in
the second half of 1999, the Company will rely upon additional sales of
promoted project interests. Delays in these projected sales will delay
certain planned drilling. In the second half of the year, it projects another
increase in its Tranche A facility with B of A. It also expects continued
rapid increases in monthly oil and gas revenues due to its exploration
successes in the first quarter of 1999. Increased revenues are anticipated to
generate significantly increasing cash flow from operations (before capital
expenditures and new 3-D seismic data acquisition costs). The Company expects
to continue to seek sources of exploration capital in addition to internally
generated resources in the first half of 2000 as it seeks to accelerate
exploratory drilling opportunities available to it.
SUMMARY. The Company believes it is positioned for a period of
significant exploration activity on its technology enhanced projects. Many of
the projects have reached the drilling stage. In many instances the requisite
process of geological and/or engineering analysis, followed by acreage
acquisition of leasehold rights and seismic permitting, and 3-D seismic field
data acquisition, then processing of the data and finally its interpretation
took several years of time and the investment of significant capital. Management
believes the acquisition of projects at this advanced stage has not only reduced
the drilling risk, but should allow the Company to consistently drill on a broad
array of exploration prospects throughout 1999.
As evidence of this activity the Company has participated in the
drilling of sixteen wells on Exploration Projects acquired pursuant to the
Acquisition in the first seven months of 1999. Of the total wells drilled in
1999 two were producing as of June 30, 1999, four more are now producing,
five are scheduled to commence production upon completion of pipeline
connections, two were dry holes and three were drilling. Based upon estimated
sustainable flow rates, the 1999 wells are anticipated to increase the
Company's net daily production to approximately 600 barrels of oil per day
and 14,000,000 cubic feet of natural gas per day. The Company expects that
these revenues will not only provide positive operating cash flow in the
second half of the year (prior to capital expenditures and new 3-D seismic
data acquisition costs, which costs the successful efforts accounting method
utilized by the Company mandates to be expensed rather than capitalized), but
begin to contribute significantly to future drilling expenditures in the
fourth quarter and beyond. 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. Pending the sale of project interests to industry
partners in the third quarter, the Company will, however, delay certain of
its drilling activities.
In that the Company will not fund most of its second half 1999 and
first half of 2000 capital expenditure budgets from cash flow, the Company will
continue to look to a variety of sources to fund its continuing capital
expenditures budget including credit facilities and sales of promoted project
interests to industry partners, as it seeks to maximize its interests and manage
its risks while aggressively pursuing its exploration projects. This process
will be limited more by capital availability than by its inventory of drillable
prospects.
Timing of funding its exploration budget will determine the pace of
drilling and, to the extent drilling is successful, the growth of future oil and
gas revenues. Management believes expanded credit facilities will be available
to it throughout the next year if it achieves meaningful exploratory and
developmental drilling success, and that strategic sales of prospect interests
will be contracted and closed which will allow it to continue its planned
exploration activities throughout the year.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In 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
20
<PAGE>
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.
21
<PAGE>
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
EPC was a defendant in a lawsuit regarding injuries to a oil field
worker not employed by the Company that resulted in a judgment against EPC of
approximately $17,700,000. The judgment was settled by EPC's insurers, who
agreed to make cash payments to the plaintiff, and by EPC who agreed to
implement a mutually agreeable work safety plan in exchange for approximately
$6.0 million in punitive damages that otherwise would have been payable to the
plaintiff. The settlement was entered into and approved by the court entering an
agreed judgment on December 3, 1997. On approximately April 16, 1998, the
plaintiff filed an action in the District Court, 28th Judicial District, State
of Texas against both EPC and the Company. The action style "Juan Ramon
Caballero vs. EPC and Frontier Natural Gas Corporation, alleged, in part, that
EPC has failed and refused to implement an appropriate safety plan and entered
into negotiations with the Company to convey material assets to it which, if
consummated, would negate plaintiffs benefits to be obtained by EPC's safety
plan, thereby fraudulently inducing plaintiff to settle the judgment against
EPC. The Company believes the claims are not supported by the facts and are
without merit. The Company has in fact implemented a safety plan as part of its
business strategy, which it believes equals or exceeds the one EPC agreed to
implement. It took this action as part of its business activities and not due to
any obligation it believes exists to the Plaintiff.
In the second quarter, the Company and EPC agreed with counsel for the
plaintiff on a procedure for verification of the Company's ongoing safety plan,
and as a result the lawsuit has been dismissed with prejudice at no cost to the
Company or EPC.
ITEM 2. CHANGES IN SECURITIES.
In the quarter ended June 30, 1999 and in the third quarter through
August 13, 1999, the Company has issued 5,250 and 33,148 shares, respectively,
of its common stock pursuant to its employees' 401-K plan. The shares represent
the employer's pro rata match of employee contributions. The shares are
presently unregistered but are intended to be registered in 1999.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM 5. OTHER INFORMATION.
On May 12, 1999, the Company announced that on May 11, 1999 it had
signed a Plan and Agreement of Merger with 3DX which provides for the merger of
3DX into the Company. The Boards of both companies have approved the
transaction, and closing of the merger is conditioned upon approval from the
shareholders of both companies and satisfaction of certain other conditions set
forth in the Plan and Agreement of Merger.
The terms of the merger provide for 3DX shareholders to receive, at
their election, either (i) the issuance of one share of common stock of the
Company for 3.25 shares of 3DX common stock; or (ii) the issuance of a new
convertible preferred stock of the Company at a ratio of one share of
convertible preferred stock for each 2.75 shares of 3DX common stock. The
preferred stock is limited to 50% of the total 3DX shares converted and may be
redeemed at the Company's sole option during the first twelve months after the
merger at $1.925 per share. If not redeemed during the first year, the preferred
will automatically convert into one share of common stock of the Company if the
average closing price of the common is greater than $1.875 during the twelfth
month after closing. If the common is less than $1.875, the preferred holder has
the right for one month to "put" the shares to the Company, which will then have
the option, at the sole election of the Company, 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.
Any share of convertible preferred stock not redeemed by the Company or
22
<PAGE>
tendered by the holder, as set forth above, by the fourteenth month after the
merger will automatically convert into one share of common stock of the
Company. The Company currently has 15,823,271 common shares outstanding and
3DX currently has 9,685,761 shares outstanding.
The Company and 3DX have filed an amended Form S-4 joint proxy
statement/registration statement with the United States Securities and Exchange
Commission. Subject to clearance of the Form S-4 by the commission, the
companies expect to hold their respective shareholders meetings in approximately
25 to 30 days.
3DX Technologies Inc. is a Houston-based exploration and production
company whose strategic business focus has been 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, if consummated, the Company will offer employment to approximately five
members of the reservoir engineering and geophysical staff of 3DX, increase its
gas and oil reserves, its monthly gas and oil revenues, and expand its ownership
of 3D seismic data and projects.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits
(2) 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
10-QSB for the quarter ended March 31, 1999 dated May
19, 1999 wherein the same appears as Exhibit 2.
(11) Computation of Earnings Per Common Share
(27.1) Financial Data Schedule
(b) Reports on Form 8-K
None.
23
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf of the
undersigned thereunto duly authorized.
ESENJAY EXPLORATION, INC.
Date: August 17, 1999 By: /S/ MICHAEL E. JOHNSON
--------------- -----------------------
MICHAEL E. JOHNSON, President,
Chief Executive Officer and Director
Date: August 17, 1999 By: /S/ DAVID B CHRISTOFFERSON
--------------- --------------------------
DAVID B. CHRISTOFFERSON,
Senior Vice President, General Counsel,
Principal Financial Officer
Date: August 17, 1999 By: /S/ BOYD C. SEWELL
--------------- -------------------------------------
BOYD C. SEWELL,
Controller and
Principal Accounting Officer
24
<PAGE>
EXHIBIT 11 TO FORM 10QSB
ESENJAY EXPLORATION, INC.
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
Three months ended June 30, Six months ended June 30,
----------------------------------------------------------------------
1999 1998 1999 1998
---------------- -------------- ------------- ----------------
<S> <C> <C> <C> <C>
BASIC EARNINGS (LOSS) PER SHARE
Weighted average common shares
outstanding.................................... 15,790,084 6,875,939 15,789,736 4,280,381
================ ============== ============= ================
Basic loss per share......................... ($0.29) ($0.73) ($0.54) ($1.32)
================ ============== ============= ================
DILUTED EARNINGS (LOSS) PER SHARE
Weighted Average Common Shares
outstanding.................................... 15,790,084 6,875,939 15,789,736 4,280,381
Shares issuable from assumed conversion of
Common share options and warrants............ --- 35,545 --- 16,206
Convertible preferred stock.................. --- --- --- ---
---------------- -------------- ------------- ----------------
Weighted average common shares
outstanding, as adjusted....................... 15,790,084 6,911,484 15,789,746 4,296,587
================ ============== ============= ================
Diluted loss per share....................... ($0.29) ($0.73) ($0.54) ($1.32)
================ ============== ============= ================
EARNINGS FOR BASIC AND DILUTED
COMPUTATION
Net loss........................................... ($4,507,922) ($5,012,130) ($8,589,400) ($5,620,719)
Preferred share dividends.......................... --- (22,350) --- (49,138)
---------------- -------------- ------------- ----------------
Net loss to common shareholders
(Basic and diluted earnings per share
computation)............................... ($4,507,922) ($5,034,410) ($8,589,400) ($5,668,857)
================ ============== ============= ================
</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.
25
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<CASH> 406,380
<SECURITIES> 0
<RECEIVABLES> 4,023,805
<ALLOWANCES> (506,148)
<INVENTORY> 0
<CURRENT-ASSETS> 5,373,800
<PP&E> 71,006,470
<DEPRECIATION> (20,100,904)
<TOTAL-ASSETS> 57,174,382
<CURRENT-LIABILITIES> 20,819,203
<BONDS> 8,350,000
0
0
<COMMON> 157,902
<OTHER-SE> 26,586,123
<TOTAL-LIABILITY-AND-EQUITY> 57,174,382
<SALES> 1,757,106
<TOTAL-REVENUES> 2,243,549
<CGS> 0
<TOTAL-COSTS> 10,832,949
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 308,439
<INCOME-PRETAX> (8,589,400)
<INCOME-TAX> 0
<INCOME-CONTINUING> (8,589,400)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (8,589,400)
<EPS-BASIC> (0.54)
<EPS-DILUTED> (0.54)
</TABLE>
