<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, 2000
[ ] 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 [ ]
18,885,190 shares as the registrant's common stock were outstanding
as of August 10, 2000.
Transitional Small Business Disclosure Format (Check one):
Yes [ ] No [ X ]
--------------------------------------------------------------------------------
<PAGE>
ESENJAY EXPLORATION, INC.
FORM 10-QSB
FOR THE QUARTER ENDED JUNE 30, 2000
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, 2000 (unaudited) and
December 31, 1999..........................................................................4
Condensed Consolidated Statements of Operations for the three months and six months
ended June 30, 2000 and 1999 (unaudited)...................................................5
Condensed Consolidated Statements of Cash Flows for the six months
ended June 30, 2000 and 1999 (unaudited)...................................................6
Notes to Condensed Consolidated Financial Statements (unaudited)...............................7
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................................................9
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, 2000 and 1999.
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, 1999 and the related
notes thereto included in Form 10-KSB and 10KSB/A as filed with the SEC.
3
<PAGE>
ESENJAY EXPLORATION, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
---------------- ----------------
(unaudited)
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents ............................................... $ 3,713,293 $ 2,598,047
Accounts receivable, net of allowance for doubtful
accounts of $455,700 at June 30, 2000 and
$519,137 December 31, ................................................. 12,552,153 7,078,109
1999
Prepaid expenses and other ............................................... 695,205 3,940,133
Receivables from affiliates .............................................. 1,058,678 363,027
---------------- ----------------
Total current assets ............................................ 18,019,329 13,979,316
Property and equipment, successful efforts method of accounting ............... 79,383,049 80,120,781
Less accumulated depletion, depreciation
And amortization ......................................................... (30,707,520) (25,937,472)
---------------- ----------------
48,675,529 54,183,309
Other assets .................................................................. 835,842 770,210
---------------- ----------------
Total assets .................................................... $ 67,530,700 $ 68,932,835
================ ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ......................................................... $ 14,366,928 $ 8,838,629
Accounts payable to affiliate, net ....................................... 188,699 2,083,913
Revenue distribution payable ............................................. 1,345,585 2,491,798
Current portion of long-term debt ........................................ 2,706,119 11,013,162
Accrued and other liabilities ............................................ 1,372,409 6,095,188
---------------- ----------------
Total current liabilities ....................................... 19,979,740 30,522,690
Long-term debt ................................................................ 13,135,663 4,750,000
Non-recourse debt ............................................................. 864,000 864,000
Accrued interest on non-recourse debt ......................................... 528,914 463,395
---------------- ----------------
Total liabilities ............................................... 34,508,317 36,600,085
Stockholders' equity:
Convertible preferred stock $.01 par value;
5,000,000 shares authorized; 356,999 shares issued and
outstanding at June 30, 2000 and December 31, 1999 .................... 3,570 3,570
Common stock:
Class A common stock, $.01 par value; 40,000,000 Shares authorized; and
18,876,834 and 18,837,699 outstanding at June 30, 2000 and
December 31, 1999, respectively ....................................... 188,768 188,377
Additional paid-in capital ............................................... 85,028,239 84,877,904
Accumulated deficit ...................................................... (52,198,194) (52,737,101)
---------------- ----------------
Total stockholders' equity ...................................... 33,022,383 32,332,750
---------------- ----------------
Total liabilities and stockholders' equity ...................... $ 67,530,700 $ 68,932,835
================ ================
</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,
2000 1999 2000 1999
--------------- --------------- --------------- ---------------
<S> <C> <C> <C> <C>
Revenues:
Gas and oil revenues ........................... $ 5,655,952 $ 792,861 $ 10,920,605 $ 1,757,106
Realized gain (loss) on commodity transactions . (1,011,184) 7,174 (1,305,178) 198,023
Gain (loss) on sale of assets .................. 3,666,815 (161,020) 8,156,718 110,632
Operating fees ................................. 100,510 89,617 225,478 153,351
Other revenues ................................. 20,743 3,915 51,929 24,437
--------------- --------------- --------------- ---------------
Total revenues ............................. 8,432,836 732,547 18,049,552 2,243,549
--------------- --------------- --------------- ---------------
Costs and expenses:
Lease operating expense ........................ 201,693 118,617 473,873 372,588
Production taxes ............................... 574,690 51,441 799,034 115,234
Transportation and gathering costs ............. 1,544 - 3,547 -
Depletion, depreciation and amortization ....... 2,556,386 556,827 4,413,109 1,175,827
Amortization of unproved properties ............ 1,440,800 1,975,000 2,881,600 4,358,000
Impairment of assets ........................... 41,989 - 41,989 -
Exploration costs - geological and geophysical . 1,493,002 578,340 1,711,107 1,252,789
Exploration costs - dry hole ................... 1,790,268 65,278 2,924,660 65,278
Interest expense ............................... 237,591 185,153 560,635 308,439
General and administrative expense ............. 2,253,425 1,678,124 3,497,621 3,082,096
Other tax expense .............................. (5,532) - 111,006 -
Delay rental expense ........................... 49,288 31,689 92,464 102,698
--------------- --------------- --------------- ---------------
Total costs and expenses ................... 10,635,144 5,240,469 17,510,645 10,832,949
--------------- --------------- --------------- ---------------
Income (loss) before provision for income taxes ..... (2,202,308) (4,507,922) 538,907 (8,589,400)
Benefit (provision) for income taxes ................ - - - -
--------------- --------------- --------------- ---------------
Net income (loss) applicable to common stockholders . $ (2,202,308) $ (4,507,922) $ 538,907 $ (8,589,400)
=============== =============== =============== ===============
Net income (loss) per common and common
equivalent share - basic .......................... $ (0.12) $ (0.29) $ 0.03 $ (0.54)
=============== =============== =============== ===============
Net income (loss) per common and common
equivalent share - diluted ........................ $ (0.12) $ (0.29) $ 0.03 $ (0.54)
=============== =============== =============== ===============
Weighted average number of common shares
outstanding - basic ( in thousands) ............... 18,865 15,790 18,854 15,790
=============== =============== =============== ===============
Weighted average number of common shares
outstanding - diluted ( in thousands) ............. 18,865 15,790 19,756 15,790
=============== =============== =============== ===============
</TABLE>
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,
-----------------------------------
2000 1999
--------------- ---------------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) .................................................... $ 538,907 $ (8,589,400)
Adjustments to reconcile net income (loss) to net cash used in
operating activities:
Depletion, depreciation and amortization ............................. 4,319,827 1,175,827
Amortization of unproven property .................................... 2,881,600 4,358,000
Gain on sale of assets ............................................... (8,156,718) (110,632)
Amortization of financing costs and warrants ......................... 93,282 37,644
Exploration costs .................................................... 2,924,660 65,278
Changes in operating assets and liabilities:
Trade and affiliate receivables .................................. (5,474,044) (163,017)
Prepaid expenses and other ....................................... 3,244,928 (508,648)
Other assets ..................................................... (65,632) (485,569)
Accounts payable ................................................. 5,528,299 (1,356,224)
Accounts payable to affiliates ................................... (1,895,214) (1,342,514)
Revenue distribution payable ..................................... (1,146,213) 1,047,321
Accrued and other ................................................ (4,722,779) 1,369,326
--------------- ---------------
Net cash used in operating activities ................................ (1,929,097) (4,502,608)
--------------- ---------------
Cash flows from investing activities:
Capital expenditures - gas and oil properties ........................ (9,369,980) (8,009,362)
Capital expenditures - other property and equipment .................. (108,230) (146,838)
Proceeds from sale of assets ......................................... 12,193,207 3,589,387
--------------- ---------------
Net cash provided by (used in) investing activities .............. 2,714,997 (4,566,813)
--------------- ---------------
Cash flows from financing activities:
Proceeds from issuance of common stock ............................... 150,726 10,837
Proceeds from issuance of debt ....................................... 19,841,782 8,820,000
Repayments of long-term debt ......................................... (19,663,162) (1,236)
--------------- ---------------
Net cash provided by financing activities ........................ 329,346 8,829,601
--------------- ---------------
Net increase (decrease) in cash and cash equivalents ............. 1,115,246 (239,820)
Cash and cash equivalents at beginning of period .......................... 2,598,047 646,200
--------------- ---------------
Cash and cash equivalents at end of period ................................ $ 3,713,293 $ 406,380
=============== ===============
Supplemental disclosure of cash flow information:
Cash paid for interest ............................................... $ 495,116 $ 644,643
=============== ===============
</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 (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
impairments for both the three and six month periods ended June 30, 2000 of
$41,989. No impairments were recognized during the three and six month period
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 is, until such time as the book value of each such project is either
drilled and transferred to producing properties or is otherwise evaluated as
impaired, are being amortized on a straight-line basis over a period not to
exceed forty-eight months. For the three and six month periods ended June 30,
2000, such amortization was $1,440,800 and $2,881,600, respectively. For the
three and six month periods ended June 30, 1999, such amortization was
$1,975,000 and $4,358,000, respectively. The remaining balance in this
amortization group of unproven properties was $10,567,100 at June 30, 2000.
A summary of all of the Company's significant accounting policies is
presented on pages 39 and 40 of its 1999 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
2000.
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 to the current period presentation.
7
<PAGE>
2. LONG-TERM DEBT:
Long-term debt consists of the following:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
-------- ------------
2000 1999
---- ----
<S> <C> <C>
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest
accrued at 15% ............................................................... $ 864,000 $ 864,000
Note payable, interest at 12%, payable monthly ................................. -- 100,000
Loan with Bank of America NT&SA ("B of A"), repaid in 2000 ..................... -- 8,523,162
Loan with Duke Energy Field Services, Inc. repaid in 2000 ...................... -- 7,140,000
Loan with Deutsche Bank AG closed on January 25, 2000 as further
Described below .............................................................. 15,841,782 --
------------ ------------
16,705,782 16,627,162
Less current portion ........................................................... 2,706,119 11,013,162
------------ ------------
$ 13,999,663 $ 5,614,000
============ ============
</TABLE>
On January 25, 2000, the Company closed a credit facility with
Deutsche Bank AG, New York branch. This facility provides for Deutsche Bank to
loan up to $29,000,000 to be available in two tranches. Tranche A is in the
amount of $20,000,000, with $12,000,000 established as the current available
borrowing base, and Tranche B is fully drawn in the amount of $9,000,000.
Under the terms and conditions of this facility, the facilities existing at
December 31, 1999 with Duke Energy Financial Services, Inc. and Bank of
America, NT&SA, were paid in full utilizing approximately $15,800,000 of the
available proceeds from Deutsche Bank. Tranche A will mature on January 25,
2001, at which time any remaining unpaid principal will convert to a fully
amortizing term loan payable in sixteen equal quarterly installments beginning
April 1, 2001. The Tranche B loan is payable interest only through April 30,
2001 at which date the amount available begins to decrease by 25% per quarter
beginning April 30, 2001 with a final maturity in January of 2002. In
addition, the Company must remain in compliance with certain covenants
required by Deutsche Bank, including a redetermination of the borrowing base
every six months. The company also is required to assign an overriding royalty
interest to Deutsche Bank for those wells logged prior to the later of the
maturity date of Tranche B or the Tranche A termination date or the date the
Tranche B Loan is repaid. The Company may repurchase this overriding royalty
interest prior to April 30, 2002, if all Tranche B loans are repaid in full.
As part of the credit agreement, the Company is subject to certain
covenants and restrictions, among which are the limitations on additional
borrowing, and sales of significant properties, working capital, cash, and net
worth maintenance requirements and a minimum debt to net worth ratio. The
covenants regarding financial condition of Company are as follows:
<TABLE>
<S> <C>
Tangible Net Worth.............................. $20,000,000 plus 50% of net income from inception of the credit
agreement to the date of calculation treated as a single period.
Current Ratio................................... 1.1 to 1.0 (computed by including unused portion of loan
commitments in current assets and excluding current portion of
long-term debt from current liabilities).
Debt to Capitalization.......................... 0.6 to 1.0
Interest Coverage Ratio......................... 3.0 to 1.0
</TABLE>
At June 30, 2000 the Company was in compliance with all such
covenants.
The Company has entered into an interest rate swap guaranteeing a
fixed Libor rate of 7.075%. The rate the Company pays Deutsche Bank is Libor
plus 2%. In addition, Company will pay fees of one-half of one percent (0.5%)
on the unused portion of the commitment amount.
8
<PAGE>
3. RELATED PARTY TRANSACTIONS
The Company's outstanding accounts receivable from employees and
affiliates of the Company at June 30, 2000 and December 31, 1999 was $1,058,678
and $363,027, respectively. The June 30, 2000 and December 31, 1999
receivables include approximately $8,664 and $47,786, respectively, from an
affiliated partnership for which the Company serves as the managing general
partner. In addition, the June 30, 2000 balance includes a net $907,833
receivable from EPC primarily related to joint interest billings. In addition,
at June 30, 2000 the Company had a net account payable to Aspect in the amount
of $188,699.
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.
In February of 2000, in conjunction with its financing with Deutsche
Bank, the Company restructured all existing natural gas hedges with an
affiliate of Deutsche Bank. Pursuant to these hedges, the Company had 9,381
MMBtu/day of net production hedged in the first quarter of 2000, and 9,031
MMBtu/day hedged for the second quarter of 2000. It also has hedged 8,646
MMBtu/day for the third quarter of 2000, 8,278 MMBtu/day for the fourth
quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001, 6,880
MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third
quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All
hedges are at $2.45 per MMBtu. Concurrent with the restructuring of the
hedges, the Company was relieved of any liability or rights pursuant to all
previously existing natural gas hedges. An existing "collar" hedge arrangement
on 280 barrels of oil per day in the first quarter of 2000, and 256 and 237
barrels of oil per day in the second and third quarters of 2000, respectively,
was transferred to the Deutsche Bank affiliate at the existing $18.00 floor
price and $20.40 cap price. These positions were supplemented with oil hedges
at $21.03 per barrel on volumes of 238 barrels of oil per day in the fourth
quarter of 2000 and 175, 168, 161, and 154 barrels of oil per day in the first
through fourth quarters of 2001, respectively. Second quarter 2000 hedges
approximated 59% of the Company's natural gas and 61% of its oil production
for such quarter. Future percentages will vary.
In 1999 the Company recorded a deferred gain on sale of $1,797,707
in relation to an ongoing sale in the Company's Papalote project. As a part of
the sales transaction the Company is required to conduct a 3-D seismic survey
over the project area. The survey was completed in the second quarter of 2000
for the project area and the gain on sale, of $1,797,707 was recognized.
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 results of operations for the three and six month periods ended June
30, 2000 and 1999 and should be read in conjunction with the consolidated
financial statements and notes related thereto. Certain statements contained
herein that set forth management's intentions, plans, beliefs, expectations
or predictions of the future are forward-looking statements. It is important
to note that actual results could differ materially from those projected in
such forward-looking statements. The risks and uncertainties include but are
not limited to potential unfavorable or uncertain results of 3-D seismic
surveys, drilling
9
<PAGE>
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,
1999. 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 the redemption of all
of its issued and outstanding cumulative convertible preferred stock and did
redeem said preferred stock. The result of the foregoing is that the Company
conveyed a substantial majority of its Common Stock to acquire an array of
significant technology enhanced natural gas oriented exploration projects.
The Company believed the Acquisitions would facilitate expanded access to
capital markets due to the value and diversity of its exploration project
portfolio. The Company also believes the transactions significantly enhanced
the Company's management team.
In connection with the Acquisitions, an affiliate of Enron Corp.
exercised an option to exchange $3.8 million of debt Aspect owed to such Enron
affiliate for 675,000 shares of the Company's Common Stock that would
otherwise have been issued to Aspect in the Acquisitions, at an effective
conversion rate of $5.63 per share.
On July 21, 1998 the Company closed an underwritten offering of
4,000,000 shares of its common stock at a price of $4.00 per share. The net
proceeds to the Company were approximately $14,880,000. After the offering the
Company had 15,762,723 shares outstanding.
On Exploration Projects acquired in 1998 pursuant to the
Acquisitions, the Company participated in the drilling of twenty-four wells
through December 31, 1998 with working interests, which range from 8% to 79%.
Out of those twenty-four wells drilled, thirteen wells have been completed and
eleven were dry holes. Several of the successful wells went into production
late in the third quarter of 1998, and in the fourth quarter of 1998.
10
<PAGE>
As a result of the above-described acquisitions, restructuring, and
the underwritten offering, the Company believed it was, and believes it
continues to be, positioned for a period of significant exploration activity
on its technology enhanced projects. Many of the projects have reached the
drilling stage. In many instances the requisite process of geological and/or
engineering analysis, followed by acreage acquisition of leasehold rights and
seismic permitting, and 3-D seismic field data acquisition, then processing of
the data and finally its interpretation, required several years and the
investment of significant capital. Management believes the acquisition of
projects at this advanced stage has not only reduced the drilling risk, but
should allow the Company to consistently drill on a broad array of exploration
prospects, as was demonstrated in 1999, and in subsequent years.
In 1999, the Company participated in 29 new wells which reached total
depth and were logged during the year. Of the total wells drilled and logged
in 1999, 22 were productive, and 7 were dry holes. Only 2 of the 1999 wells
were producing as of July 1, 1999, and as a result the Company's net daily oil
and gas production increased substantially throughout the third and fourth
quarters of 1999. Based upon estimated sustainable flow rates, the 1999 wells
helped to increase the Company's net daily production to approximately 532
barrels of oil per day and 14,605 million cubic feet of natural gas per day or
17,797 Mcfe per day as of December 1999.
The Company's net cost in the 29 wells drilled in 1999 was
approximately $8,652,439 for drilling and completion, not including certain
prior expenditures incurred at the project level for land and seismic. It
should be noted that the Company defines a "project" as a distinct 3-D seismic
data area which often comprises several distinct exploratory "prospects". Net
proved reserves attributable to the 29 wells drilled in 1999 totaled
18,466,712 Mcfe including 1999 production and December 31, 1999 remaining
reserves as independently evaluated.
The Company ended 1999 having gone from nominal third quarter 1998
gas and oil revenues of approximately $35,000 per month and large operating
cash flow deficits to a company which averaged $1,815,637 per month in net oil
and gas revenues and associated hedging revenues from commodity transactions
in the fourth quarter of 1999. This number increased significantly as the
wells drilled in 1999 continued to come on line. This allowed the Company to
achieve positive operating cash flow (before capital expenditures, and before
the costs of acquisition of new 3-D seismic data, and changes in working
capital) in the third quarter, which operating cash flow increased in the
fourth quarter. As a result of this trend, approximately 56% of the Company's
1999 gas and oil revenue was attributable to the fourth quarter of the year.
On September 23, 1999, the Company acquired, via merger, 3DX
Technologies, Inc. ("3DX"). As a result, Esenjay issued approximately
2,906,800 new shares of common stock and approximately 357,000 shares of
convertible preferred stock, which convertible preferred stock is scheduled to
be converted or redeemed (at the Company's option) not later than November 1,
2000. The Company intends to redeem the convertible preferred stock in
September of 2000 at a price of $1.925 per share for a total redemption price
of approximately $687,200.
OVERVIEW OF 2000 ACTIVITIES. The Company believes it entered 2000 in
a position to continue to expand its exploration activities on its
technology-enhanced projects. By utilizing its increased capital available to
it from cash flow, financings and industry partner transactions, the Company
is pursuing an aggressive exploration budget in all of its major trends of
activity. The Company's net daily production averaged 505 barrels of oil per
day and 15,416 Mcf of natural gas per day in the first quarter of 2000, and
418 barrels of oil per day and 15,197 Mcf per day of natural gas in the second
quarter of 2000. This second quarter decline was primarily due to production
problems on one well incurred early in the second quarter. As additional wells
commenced production, the daily production increased during the second quarter
and averaged 425 barrels of oil per day and 17,499 Mcf per day of natural gas
in June of 2000. This net production is after a reduction of 6 barrels of oil
per day and 1,981 Mcf of natural gas per day attributable to the sale of
interests in the Raymondville Project as described below in the following
paragraph.
The Company has also successfully improved its working capital and
cash resources. On February 7, 2000, it announced the closure of a $29 million
credit facility with Deutsche Bank AG, New York Branch. Initial availability
pursuant to the facility was $21 million with a borrowing base adjustment
scheduled for the second quarter of 2000. A portion of the available proceeds
was utilized to retire approximately $15.8 million of previously existing debt
with Bank of America and Duke Energy Financial Services, Inc., of which
approximately $11 million was classified as the current portion of long-term
debt. The amount outstanding under the new facility was all classified as long
term debt upon inception. $2,706,119 is classified as current portion as of
June 30, 2000. Effective June 30, 2000, the borrowing base was increased to
$24 million. In addition, the Company sold approximately 84.39% of its
interest in its
11
<PAGE>
Raymondville Project in Willacy County to Cody Texas, L.P. for cash proceeds
of $10,949,000 ($10,535,764 net of transaction fees). The sale closed on March
20, 2000 but was effective as of January 1, 2000. Pursuant to this sale the
Company sold 3,462,967 Mcfe of its reserves classified as proved as of
December 31, 1999. Its borrowing base availability with Deutsche Bank was not
reduced. The combination of these two financing transactions have made
available $18.8 million in net additional cash resources (after repayment of
existing debt) and created significant positive improvements in working
capital for the Company. As a result of its current cash flow and the impact
of these two transactions, the Company believes it is positioned to fund a
substantial portion of its 2000 drilling activities, the results of which are
intended to help continue the upward trends of increasing cash flow and
reserves. The Company will look to a variety of sources to further supplement
its capital expenditures budget, including its credit facilities and sales of
additional promoted project interests to industry partners, as it seeks to
maximize its interests and manage its risks while aggressively pursuing its
exploration projects.
In the six months ended June 30, 2000, the Company incurred
approximately $9,200,000 in year 2000 drilling and completion expenditures
and $3,800,000 in year 2000 land and seismic costs. In the first quarter of
2000, the Company participated in 8 new wells which reached total depth and
were logged during the quarter. Of these 8 wells, 5 were dry holes and 3 are
producing. In the quarter ended June 30, 2000, the Company participated in 18
new wells. 14 of the 18 wells were drilled to total depth during the quarter,
3 additional wells have subsequently drilled to total depth, and 1 of the
wells is still drilling. Of these 17 second quarter wells that drilled to
total depth, 7 are producing, 2 are being completed, and 8 were dry holes.
The Company experienced production problems with one well early in
the second quarter which averaged approximately 2,300 Mcf and 126 barrels of
oil per day in the first quarter. Production from this well was minimal in the
second quarter of 2000 and its future contributions to overall Company
production is uncertain. This served to impede second quarter production
revenue growth. As a result, April and May production was down as contrasted
with the first quarter. As additional wells came on line, June production
averaged 20,049 Mcf equivalent resulting in increasing production.
Certain projects of the Company were subject to an agreement with
Seagull Energy E&P, Inc. ("Seagull"), a subsidiary of Ocean Energy, Inc.,
which agreement provided an option in favor of Seagull to acquire 50% of the
Company's unproven interests in the Mikeska and Hall Ranch projects for
$6.5 million, plus, at Seagull's option, 50% of the Company's unproven
interests in the Orangedale, Verdad, Hordes Creek and Riverdale projects for
an additional $2.0 million. The option is set to expire in the third quarter
of 2000 and Ocean has advised the Company it will not exercise it.
The Company has budgeted $18,000,000 in drilling and completion
expenditures on interests in over 40 wells and an additional $8,000,000 in
land and new seismic costs in 2000. The budgeted drilling and completion
expenditures, which are primarily on exploratory wells, compares to total
drilling and completion expenditures of approximately $8,652,439 in 1999 when
the Company had less capital available. Through this exploration program, the
Company believes it can resume its 1999 trends of growth in net production,
net revenues, operating cash flow, and net gas and oil reserves in the second
half of the year 2000 and beyond. It believes that certain of its planned
2000 exploratory wells represent the highest upside potential to which the
Company has been exposed.
SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company
utilizes the successful efforts method of accounting. Under this method it
expenses its exploratory dry hole costs and the field acquisition costs of 3-D
seismic data as incurred. The undeveloped properties, which were acquired
pursuant to the Acquisitions, were comprised primarily of interests in
unproven 3-D seismic based projects, and were recorded in May of 1998 at an
independently estimated fair market value of $54.2 million as determined by
Cornerstone Ventures, L.P., a Houston, Texas based investment banking firm.
Pursuant to the successful efforts method of accounting, the Company is
amortizing such initial costs of unproved properties on a straight-line basis
over a period not to exceed forty-eight months, as well as recognizing
property specific impairments. As of June 30, 2000 the unamortized balance was
$10,567,100. Hence significant non-cash charges have depressed reported
earnings of the Company and will likely continue to do so in 2000; however,
the non-cash charges will not affect cash flows provided by operating
activities nor the ultimate realized value of the Company's natural gas and
oil properties.
As a result of the tax rules applicable to the Acquisitions, the
Company will likely not be able to fully use its existing net operating loss
carry forward in the future.
12
<PAGE>
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
2000 1999 2000 1999
-------------- ----------- ------------- -------------
<S> <C> <C> <C> <C>
PRODUCTION:
Gas (MMcf) ......................... 1,382.90 274.30 2,828.60 1,026.30
Oil and condensate (MBbls) ......... 38.00 1.50 84.60 13.70
Total equivalent (Mmcfe) ........... 1,610.90 283.00 3,336.20 1,108.50
AVERAGE SALES PRICE:(2)
Gas (per Mcf) ...................... $ 3.35 $ 2.08 $ 3.01 $ 1.87
Oil and condensate (per Bbl) ....... $ 26.84 $ 15.87 $ 27.10 $ 13.63
AVERAGE EXPENSES (PER MCFE):
Lease operating (1) ................ $ 0.12 $ 0.42 $ 0.14 $ 0.34
Depletion of oil and gas properties: $ 1.58 $ 1.96 $ 1.32 $ 1.06
</TABLE>
(1) Includes all direct expenses of operating the Company's properties, as well
as production and ad valorem taxes.
(2) Including the effects of hedging activities the average gas and oil
sales price was $3.01/mcf and $24.96/bbl for the three months ended
June 30, 2000 and $2.11/mcf and $15.87/bbl for the three months ended
June 30, 1999 respectively and $2.85/mcf and $24.91/bbl for the six months
ended June 30, 2000 and $2.06/mcf and $13.63/bbl for the six months ended
June 30, 1999 respectively.
THREE MONTHS ENDED JUNE 30, 2000 COMPARED WITH THREE MONTHS ENDED JUNE 30, 1999
REVENUE. Total revenues increased 1,051.17% from $732,547 for the
second quarter ended June 30, 1999 to $8,432,836 for the second quarter ended
June 30, 2000. This is primarily attributed to the factors set forth below.
GAS AND OIL REVENUES. Total gas and oil revenues increased from
$792,861 for the second quarter of 1999 to $5,655,952 for the second quarter
of 2000. This resulted in a 613.36% increase to gas and oil revenue. The
increase is attributable to a combination of the increase in commodity sales
prices in the second quarter of 2000, as contrasted with 1999, and in an
increase in the Company's net gas and oil production in the year 2000. The
average sales price per Mcf in gas increased from $2.08 per Mcf in the second
quarter of 1999 to $3.13 in the second quarter of 2000, and the average sales
price per barrel of oil and/or condensate increased from $15.87 in the second
quarter of 1999 to $34.69 in the second quarter of 2000. Net gas production
increased from approximately 274,300 Mcf for the second quarter of 1999 to
approximately 1,382,900 Mcf in the second quarter of 2000. Net oil and/or
condensate production increased from approximately 1,500 barrels in the second
quarter of 1999 to approximately 38,000 barrels in the second quarter of 2000.
REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. In the second quarter
of 1999, the Company realized a gain of $7,174 on commodity transactions, as
contrasted with a loss of $1,011,184 in the second quarter of 2000. This gain
(loss) results from actual commodity prices being greater or less than the
Company's hedged price on natural gas or oil. This change is attributable to
the increase in gas and oil prices such that the hedges currently in place on
the Company's production portfolio were at lower prices for the second quarter
of 2000 as contrasted with commodity prices in the second quarter of 1999 at
which time a slight gain was realized. Although the Company has hedges in
place at higher prices in the second quarter of 2000 than in the second
quarter of 1999, commodity prices increased more resulting in the loss for the
period. The Company currently has hedges in place in volume amounts which
decrease quarterly and end December 31, 2000. (See "Liquidity and Capital
Resources")
GAIN ON SALE OF ASSETS. The gain on sale of assets in the second
quarter of 2000 of $3,666,815 is attributable to sales of interests to
industry partners in certain of the Company's projects. The largest component
was a gain of $1,797,707 recognized in conjunction with a sales transaction
with an interest in a 3-D seismic project overlying the Company's Papalote
Project area. The balance of the gain was comprised of gains on a series of
smaller sales, primarily sales of working interests to industry partners in
wells anticipated to be drilled in the year 2000.
13
<PAGE>
OPERATING FEES. The increase in revenue from operations from $89,617
in the second quarter of 1999 to $100,510 in the second quarter of 2000 is
basically attributable to increased volume of activity.
OTHER REVENUES. Other revenues in the second quarter of the year 2000
were comprised of interest income, which increased from $3,915 in the second
quarter of 1999 to $20,743 in the second quarter of 2000.
COSTS AND EXPENSES. Total costs and expenses of the Company increased
102.94% from $5,240,469 for the second quarter ended June 30, 1999 to
$10,635,144 for the second quarter ended June 30, 2000. This is primarily due
to changes discussed in the categories below.
LEASE OPERATING EXPENSES. Lease operating expense increased 70.04%
from $118,617 for the second quarter of 1999 to $201,693 for the second
quarter of 2000. This is due to the increased number of producing wells owned
by the Company.
PRODUCTION TAXES. Production taxes increased 1,017.18% from $51,441
for the second quarter of 1999 to $574,690 for the second quarter of 2000. The
increase in production taxes is primarily attributable to revenues from wells
placed in production in late 1999 and early 2000.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A"). Depreciation,
depletion and amortization ("DD&A") increased 359.10% from $556,827 for the
second quarter of 1999 to $2,556,386 for the second quarter of 2000. The
increase to DD&A was attributed to wells placed in production in late 1999 and
early 2000.
AMORTIZATION OF UNPROVED PROPERTIES. Amortization of unproved
properties decreased from $1,975,000 for the second quarter of 1999 to
$1,440,800 for the second quarter of 2000. This is due to reductions in the
book value of the amortizing assets due to transfer to proven properties and
the sale of interests in some projects. 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").
IMPAIRMENT OF ASSETS. The Company recognized impairments of $41,989
for the three months ended June 30, 2000 as compared to none for the three
months ended June 30, 1999.
EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL. Exploration costs
-geological and geophysical increased 158.15% from $578,340 for the second
quarter of 1999 to $1,493,002 for the second quarter of 2000. 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.
EXPLORATION COSTS - DRY HOLE. Exploration costs - dry hole increased
2,642.53% from $65,278 for the second quarter of 1999 to $1,790,268 in the
second quarter of 2000. The increase is attributable to the increased volume
of drilling activity.
INTEREST EXPENSE. Interest expense increased 28.32% from $185,153 for
the second quarter of 1999 to $237,591 for the same period 2000 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 $120,302 for the second
quarter of 2000.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative
expenses increased 34.28% from $1,678,124 for the second quarter of 1999 to
$2,253,425 for the second quarter of 2000. This was primarily attributable to
payment of $582,000 in cash bonus payments pursuant to a Company-wide bonus
program based upon 1999 drilling results.
NET LOSS PER COMMON SHARE. Net loss per common share decreased from a
net loss of $0.29 per share for the second quarter of 1999 to a net loss of
$0.12 per share for the second quarter of 2000. Due to the factors enumerated
above, there was a decrease in net loss applicable to common stockholders of
$2,305,614 from the second quarter of
14
<PAGE>
1999 as compared to the second quarter of 2000. Approximately 18,865,000
weighted average common equivalent shares were outstanding at June 30, 2000 as
compared with approximately 15,790,000 at June 30, 1999, which further
influenced the change in net loss per share in 2000.
SIX MONTHS ENDED JUNE 30, 2000 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1999
REVENUE. Total revenues increased 704.51% from $2,243,549 for the six
months ended June 30, 1999 to $18,049,552 for the six months ended June 30,
2000, due to the factors listed below.
GAS AND OIL REVENUES. Total gas and oil revenues increased from
$1,757,106 for the six months ended June 30, 1999 to $10,920,605 for the six
months ended June 30, 2000. This increase is primarily attributable to wells
placed in production in late 1999 and early 2000, which resulted in an
increase in the Company's net production. It was further impacted by general
increases in commodity prices, which increases became more pronounced in June
of 2000.
REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. The Company realized
a loss from various commodity transactions of $1,305,178 for the six months
ended June 30, 2000. This contrasted with a net gain of $198,023 in the first
six months of 1999. This gain (loss) results from actual commodity prices for
the period being greater or less than the Company's hedge price on natural gas
or oil. Although the Company has hedges in place at higher prices in the first
six months of 2000 than in the first six months of 1999, commodity prices
increased more resulting in the loss for the period.
GAIN ON SALE OF ASSETS. There was an increase in gain on sale of
assets from $110,632 for the six months ended June 30, 1999 to $8,156,718 for
the six months ended June 30, 2000. The increase was due to the closing of
various project interest sales to third parties, which resulted in an
aggregate gain for the period. The majority of the gain was attributable to
recognition of the gain on the sale of interests in the Papalote Project to an
industry partner of $1,797,707 and the booked gain on the sale of the
Company's Raymondville Project of approximately $6,607,211.
OPERATING FEES. The increase in revenue from operating fees from
$153,351 in the first six months of 1999 to $225,478 in the first six months
of 2000 is attributable to the increased volume of the Company's activity.
OTHER REVENUES. The increase in other revenues from $24,437 in the
first six months of 1999 to $51,929 in the first six months of 2000 was
attributable to an increase in interest income.
COSTS AND EXPENSES. Total costs and expenses of the Company increased
61.64% from $10,832,949 for the six months ended June 30, 1999 to $17,510,645
for the six months ended June 30, 2000. The primary factors are set forth
below.
AMORTIZATION OF UNPROVED PROPERTIES. Amortization of unproved
properties was $2,881,600 for the six months ended June 30, 2000 compared to
$4,358,000 in the first six months of 1999. The 33.88% decrease is
attributable to reductions in the basis of properties being amortized due to
certain properties being moved to the proven property category or, in certain
instances, certain interests in certain properties having been sold and the
basis therefor removed from the amortization pool. The Company will amortize
the undeveloped and unevaluated value of the properties acquired pursuant to
the Acquisition over a period not to exceed forty-eight months. (See "Overview
- Successful Efforts Accounting and Related Matters").
IMPAIRMENT OF ASSETS. The Company recognized impairments of $41,989
for the six months ended June 30, 2000 as compared to none for the six months
ended June 30, 1999.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative
expenses increased 13.48% from $3,082,096 for the six months ended June 30,
1999 to $3,497,621 for the six months ended June 30, 2000. This was primarily
due to payment of $582,000 in cash bonus payments pursuant to a Company-wide
bonus based upon 1999 drilling results.
DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A"). Depletion,
depreciation and amortization ("DD&A") increased 275.32% from $1,175,827 for
the six months ended June 30, 1999 to $4,413,109 for the six months ended
15
<PAGE>
June 30, 2000. The increase in DD&A was primarily attributed to wells placed
in production during late 1999 and early 2000.
LEASE OPERATING EXPENSES. Lease operating expenses increased 27.18%
from $372,588 for the six months ended June 30, 1999 to $473,873 for the six
months ended June 30, 2000. The increase in lease operating expenses relates
primarily to operational cost for the Company's wells placed in production
during late 1999 and early 2000.
INTEREST EXPENSE. Interest expense increased 81.77% from $308,439 for
the six months ended June 30, 1999 to $560,635 for the six months ended June
30, 2000. The increase in interest expense was attributable to increased
borrowing pursuant to its credit facility. 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 $182.607 for the six months ended June 30, 2000.
PRODUCTION TAXES. Production taxes increased 593.40% from $115,234
for the six months ended June 30, 1999 to $799,034 for the six months ended
June 30, 2000. This increase in production taxes was attributed to revenues of
wells placed in production late 1999 and early 2000.
EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL. Exploration costs
-geological and geophysical increased 36.58% from $1,252,789 for the six
months ended June 30, 1999 to $1,711,107 for the six months ended June 30,
2000. The increase resulted from an increase in the acquisition of new 3-D
seismic field data in 2000. 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.
EXPLORATION COSTS - DRY HOLE. Exploration costs - dry hole increased
4,380.31% from $65,278 for the six months ended June 30, 1999 to $2,924,660
for the six months ended June 30, 2000. The increase is attributable to the
increased volume of drilling activity.
NET INCOME (LOSS) PER COMMON SHARE. Net income per common share
increased from a net loss of $0.54 per share for the six months ended June 30,
1999 to a net income of $0.03 per share for the six months ended June 30,
2000. Due to factors mentioned above, there was an increase in net income
applicable to common stockholders of $9,128,307 from the six months ended June
30, 1999 as compared to the six months ended June 30, 2000. Approximately
18,854,000 weighted average common equivalent shares were outstanding for the
six months ended June 30, 2000 as compared with approximately 15,790,000 at
June 30, 1999, which further influenced the change in net income per share in
2000.
KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE
OPERATING RESULTS.
The Company's future operating results will continue to be
substantially dependent upon the success of the Company's efforts to develop
the projects acquired in the Acquisitions and the acquisition of 3DX, as well
as its other prospects.
Management continues to believe these projects represent the most
promising prospects in the Company's history. The wells drilled in 1998, 1999
and 2000 on projects acquired pursuant to the Acquisitions continue to
increase the Company's year 2000 revenues as compared with 1999. Conversely,
the capital expenditures planned in 2000 will continue to require substantial
outlays of capital to explore, develop and produce. Drilling results for 1998
resulted in substantial revenue increases. Drilling results in 1999 resulted
in rapidly expanding revenues in the third and fourth quarters of 1999.
However, because of the Company's expanded 2000 drilling budget, capital from
sources other than cash flow from operations is required for funding planned
exploration activities. The Raymondville Interests Sale closed in the first
quarter has, however, provided the cash resources to substantially fund the
2000 capital budget when combined with available credit facilities and
anticipated operating cash flow. The Company's 2000 budget remains
significantly funded from cash on hand, available credit and anticipated cash
flow.
16
<PAGE>
The trend of increasing revenues was slowed by the sale of the
Raymondville Interests, effective January 1, 2000, a reduction of
approximately 2,000 Mcfe per day, the production problems incurred on one well
early in the second quarter, which resulted in a reduction of approximately
2,300 Mcf and 126 bbls of oil per day, and natural decline rates. This was
significantly offset by increases in product prices. Wells which came on line
in the second quarter increased the Company's production to 20,049 net
Mcfe per day in June of 2000. Continued upward growth in revenue will be
dependent upon the Company's continued drilling success on wells currently
drilling and to be drilled through 2000. The budget will, however, continue to
include the sales of certain project interests to industry partners; however,
the Company believes it will be much less dependent upon such sources due to
its increasing operating cash flow, improved liquidity, and new credit
facility.
LIQUIDITY AND CAPITAL RESOURCES
The Company 2000 business plan provided for net expenditures of
$18,000,000 in drilling and completion and $8,000,000 in land and geophysical
costs resulting in a $26,000,000 capital budget for 2000. In the six month
period ended June 30, 2000, the Company incurred approximately $9,200,000 in
drilling and completion costs, which costs were partially offset by cash fees
paid or due to the Company by industry partners for interests in the wells
drilled. The Company also incurred approximately $3,800,000 in land and
geophysical costs in the six month period. The geophysical costs were
partially offset by cash fees paid or due to the Company by industry partners
in conjunction with 3-D surveys, including a $1,166,666 fee paid by one
partner in the quarter. These budgeted amounts are based upon exploration
opportunities and may be adjusted based upon available capital, new
opportunities and industry conditions. The Company believes its capital
spending will be consistent with the budget in 2000. The Company's sources of
financing include borrowing capacity under its credit facilities, the sale of
promoted interests in the Exploration Projects to industry partners and cash
provided from operations. The Company's budget includes the sales of certain
project interests to industry partners.
The Company entered 1999 having gone from nominal second quarter 1998
gas and oil production revenues of approximately $35,000 per month and large
operating cash flow deficits to a company which averaged $1,815,637 per month
in oil and gas revenues and in realized revenue from hedges on production in
the fourth quarter of 1999. These revenues averaged $1,754,884 per month in
the first quarter of 2000; however, $122,884 of this average was attributable
to adjustments to prior periods and the average gas and oil revenues for
actual first quarter 2000 production was $1,632,000 per month. This was
achieved after the sale of interests in the Raymondville Project, which sale
was effective January 1, 2000. Second quarter gas and oil revenues averaged
$1,885,317 per month. The revenues for the quarter were disproportionately
attributable to the month of June as both production volumes and product
prices had increased. The Company believes its third quarter 2000 average
daily production from existing wells will approximate 20,000 net Mcfe per day.
Additional success in 2000 on wells currently drilling, if obtained, would
result in continued increases in production in 2000.
The Company ended 1999 with a deficit working capital of
approximately $16,543,374. Of this amount approximately $11.0 million was
represented by the current portion of its long term debt. This deficit working
capital was greatly improved when the Company, on January 25, 2000, closed a
new credit facility with Deutsche Bank AG, New York Branch. Pursuant to this
facility, all of the $15.8 million of the Company's long term debt at December
31, 1999 was repaid. This repayment included $4.8 million of long term debt
classified as long term and the repayment of approximately $11.0 million of
long term debt classified as current. Pursuant to the Deutsche Bank credit
facility, $21 million was initially available. This was increased at June 30,
2000 to $24 million. All amounts available were long term debt, $2,706,119 of
which is classified as current portion at June 30, 2000, but which is not due
until 2001. The credit facility with Deutsche Bank is in two tranches. $12
million was initially available under Tranche A, and $9 million under Tranche
B. Tranche A has been increased to $15 million. Tranche A is a revolving
facility with no required principal payments until January 24, 2001, after
which date it converts into a four-year term loan. Tranche B is payable
interest only until the second quarter of 2001, at which time the principal is
amortized at a rate of 25% per quarter until fully repaid. Both loans are at a
varied interest rate utilizing either Deutsche Bank's alternative interest
rate or the London interbank rate plus 2% for both Tranche A and Tranche B. As
of August 7, 2000, $6,841,782 was drawn under Tranche A and $9 million under
Tranche B. All undrawn funds will be available for future activities of the
Company. The facility is secured by a mortgage on most of the proven
properties currently owned by the Company. In addition, the Company has a
negative pledge and an agreement to mortgage any of the Company's unproven
projects or properties at the demand of the bank. In addition to the
foregoing, Deutsche Bank AG received a
17
<PAGE>
1.5% overriding royalty interest, proportionately reduced to the Company's net
interest, on the gas and oil properties classified as proven as of the date of
closing, and an agreement that it would convey to the bank a 1.5% overriding
royalty interest, proportionately reduced to the Company's net interest, on
future proven wells on the date any such future wells are logged, for as long
as funds are outstanding pursuant to Tranche B. In the event the Tranche B
loans are repaid in full prior to April 30, 2002, the Company may redeem the
overriding royalty interests conveyed to Deutsche Bank AG for an amount equal
to (a) an amount which, when added to the interest paid to Deutsche Bank AG,
plus revenues received by Deutsche Bank AG from the overriding royalties
conveyed to Deutsche Bank AG, would provide to Deutsche Bank AG an internal
rate of return of approximately 15%, plus (b) 60% of the then remaining
present value of the overriding royalties to be redeemed after subtracting the
amount calculated in (a) above. In addition, Deutsche Bank also received a
five-year warrant to purchase 250,000 shares of the Company's common stock at
a price equal to $1.50 per share. Proceeds of the credit facility were
utilized to retire the Company's existing long-term debt and additional
proceeds can be utilized to supplement working capital and exploration costs.
The Company expects further increases in the borrowing base in the event its
proven oil and gas reserves continue to grow.
The Company's working capital was further enhanced when it closed a
sale of project interests to Cody Texas, L.P. for an amount net to the Company
totaling approximately $10,535,764 on March 20, 2000. In this sale, the
Company conveyed 84.39% of its net interest in its Raymondville Project in
Willacy County, Texas to Cody Texas, L.P. The Company's borrowing base
pursuant to Tranche A with Deutsche Bank was not reduced as a result of the
sale. The proceeds of the sale of interests to Cody Texas, L.P. were utilized
to increase working capital, to reduce outstanding amounts under the revolving
borrowing base available to the Company pursuant to Tranche A of the Deutsche
Bank facility, and to fund capital expenditures of the Company.
In the second quarter of 2000, the Company finalized a bonus to
employees for results achieved in 1999. The bonus was primarily based upon
drilling results achieved as contrasted with drilling and completion costs
incurred to achieve the results. On 1999 drilling, the Company achieved a
significant return on drilling and completion costs incurred. The bonus is
payable in two installments. $581,934 was paid in the second quarter of 2000.
A second payment is subject to revised engineering reports on wells drilled
in 1999, but is currently estimated to be substantially less. It will be paid
in the third quarter of 2000.
The Company believes that in 2000 it has achieved a much more
desirable position from a standpoint of liquidity than it has experienced
since the consummation of the Acquisitions in May of 1998. Improvements to its
working capital position, which have resulted from the closing of the facility
with Deutsche Bank and the sale to Cody Texas, L.P., combine with the
Company's recently increased cash flow to place it in a good position to
significantly fund its year 2000 capital expenditures budget from cash,
currently available credit and anticipated operating cash flow. Given the
currently estimated $26 million capital expenditure budget, approximately
fifty percent of which is anticipated in the third and fourth quarters, the
Company anticipates that the full funding of said budget will likely still
depend upon some sales or other transactions with industry partners in the
second half of the year 2000. Its ongoing business plan is to always implement
such transactions in order to properly manage the spread of risk in its
drilling activities as well as to be a source of capital expenditure funds.
Pursuant to the Company's credit agreement with Deutsche Bank, it has
certain covenants regarding current interest coverage ratios and other
covenants regarding which it is expected to be in compliance at the end of
each quarter. Although the Company believes it will be in compliance with
these covenants in the year 2000, there can be no assurance that it will be in
compliance. In the event it is not in compliance, the Company will be required
to seek waivers of said covenants or would be required to seek alternative
financing arrangements. The Company was in compliance at June 30, 2000.
The Company historically has addressed its long-term liquidity needs
through the issuance of debt and equity securities, through bank credit and
other credit facilities, sales of project interests to industry partners and
with cash provided by operating activities. Its major obligations as of June
2000, consisted principally of (i) servicing loans under the credit facilities
with Deutsche Bank and other loans, (ii) funding of the Company's exploration
activities, and (iii) funding of the day-to-day operating costs.
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The Company has an ambitious capital expenditure plan for 2000, which
includes approximately $18,000,000 in drilling and completion costs, and an
additional $4,600,000 and $3,600,000, respectively, in geological, geophysical
and land costs for the year. In the first six months, the Company incurred
approximately $9,200,000 in drilling and completion costs, and approximately
$3,800,000 in geological and geophysical costs and land costs. It plans
similar total capital costs will be incurred in the third and fourth quarters.
Cash on hand, cash currently available pursuant to the Deutsche Bank credit
facility, and cash flow from operations will contribute significantly to said
budgets, but additional funds in the form of sales of project interests and/or
long term debt will likely be needed in the second half of the year.
In addition to the capital expenditures budgeted, the Company has the
right to redeem its currently outstanding preferred stock in September of
2000. It intends to do so. It has 356,999 shares of preferred stock
outstanding and can redeem said shares at $1.925 per share. It believes this
to be a favorable price and expects to invest a total of approximately
$687,200 for redemption of all of said preferred stock in the third quarter.
Many of the factors that may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control,
including, but not limited to, oil and natural gas prices, governmental
actions and taxes, the availability and attractiveness of financing and its
operational results. The Company continues to examine alternative sources of
long-term capital, including the acquisition of a company with producing
properties for common stock or other equity securities, and also including
bank borrowings, the issuance of debt instruments, the 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. It also seeks to be
aware of any consolidation opportunities with other companies that may help
increase shareholder value.
The Company markets its natural gas through monthly spot sales.
Because sales made under spot sales contracts result in fluctuating revenues
to the Company depending upon the market price of gas, the Company may enter
into various hedging agreements to minimize the fluctuations and the effect of
price declines or swings. In February of 2000, in conjunction with its
financing with Deutsche Bank, the Company restructured all existing natural
gas hedges with an affiliate of Deutsche Bank. Pursuant to these hedges, the
Company had 9,381 MMBtu/day of net production hedged in the first quarter of
2000, and 9,031 MMBtu/day hedged for the second quarter of 2000, and it has
8,646 MMBtu/day hedged for the third quarter of 2000, 8,278 MMBtu/day for the
fourth quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001, 6,880
MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third
quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All
hedges are at $2.45 per MMBtu. Concurrent with the new hedges, all prior
natural gas hedges were retired. In September of 1999, the Company entered
into a "collar" hedge arrangement on certain of its oil production. It entered
into an oil hedge for a quantity equal to 300 barrels of oil per day in the
fourth quarter of 1999, 280 barrels of oil per day in the first quarter of
2000, 256 barrels of oil per day in the second quarter of 2000, and 237
barrels of oil per day in the third quarter of 2000, all of which transactions
were structured with an $18.00 floor price and a $20.40 cap price. These
positions were supplemented with oil hedges for 238 barrels of oil per day in
the fourth quarter of 2000, and 175 barrels of oil per day, 168 barrels of oil
per day, 161 barrels of oil per day and 154 barrels of oil per day for the
first through fourth quarters of 2001, respectively, all of which supplemental
hedges were at $21.03 per barrel. As a result of the above-referenced
transactions, the Company has hedged varying quantities of its natural gas and
oil production through December of 2001. Second quarter 2000 hedges
approximated 59% of the Company's natural gas and 61% of its oil production
for such quarter. Future percentages will vary.
WORKING CAPITAL. At June 30, 2000, the Company had a cash balance of
$3,713,293, total current assets of $18,019,329, and total current liabilities
of $19,979,740. This resulted in a working capital deficit of $1,960,411. The
Company expects its trend of increasing gas and oil revenues and associated
hedging revenues from commodity transactions will continue the growth in
revenues in excess of the ongoing costs of operations, which may also enhance
the Company's working capital position. Conversely, the Company utilizes
excess cash to reduce its revolving line of credit which may result in lower
reported working capital than would be reported were it to utilize more
long-term debt, but does not affect available cash resources. Tranche B of the
Deutsche Bank facility begins amortizing at a rate of 25% of the principal per
quarter in the second quarter of 2001. Tranche A is scheduled to amortize over
four years beginning in the first quarter of 2001; however, the intention of
the Company and the bank is to extend the commencement of the amortization
period assuming satisfactory financial performance by the
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Company. The amortization schedules will result in increases in the Company's
current portion of long-term debt in 2000 but will not affect cash available
in 2000. The net working capital can be negatively effected by the Company's
continuing aggressive capital expenditures program on its exploration projects
to the extent said capital expenditures exceed cash generated from operations
and from the sale of project interests and/or growth in its credit facilities.
SUMMARY. The Company believes it is positioned to continue to expand
its exploration activity on its technology-enhanced projects. Many of the
projects have reached the drilling stage. In many instances the requisite
process of geological and/or engineering analysis, followed by acreage
acquisition of leasehold rights and seismic permitting, and 3-D seismic field
data acquisition, then processing of the data and finally its interpretation
took several years of time and the investment of significant capital.
Management believes the acquisition of projects at this advanced stage has not
only reduced the drilling risk, but should allow the Company to consistently
drill on a broad array of exploration prospects throughout 2000 and beyond.
As evidence of this activity the Company participated in the drilling
of 23 wells on its exploration projects in the first six months of 2000, not
including wells commenced after July 1. The addition of wells drilled in 1999
and 2000 to producing status has increased the Company's net daily production
to approximately 418 barrels of oil per day and 15,198 Mcf of natural gas per
day in the second quarter of 2000, of which 425 net barrels of oil per day and
17,499 net Mcf of natural gas per day were attributable to June 2000
production. The Company expects that the associated revenues will provide
positive growing operating cash flow throughout 2000 (prior to capital
expenditures and new 3-D seismic data acquisition costs, which costs the
successful efforts accounting method utilized by the Company mandates to be
expensed rather than capitalized). The Company's 1999 and 2000 drilling
results have further served to increase its confidence in its future drilling
on the technology enhanced Exploration Projects. Additional exploration
success would continue this positive trend.
The Company expects to fund significant portions of its $18 million
year 2000 drilling and completion budget from operating cash flow (prior to
capital expenditures and new 3-D seismic data acquisition costs). Its total
capital budget, including land and new seismic, of $26 million is
significantly funded from cash available, anticipated cash flow and available
credit facilities. These amounts will be supplemented by continued sales of
interests to industry partners. The Company will utilize a variety of sources
to fund its continuing capital expenditures budget including operating cash
flow, currently available credit facilities and certain sales of promoted
project interests to industry partners, as it seeks to maximize its interests
and manage its risks while aggressively pursuing its exploration projects.
The Company intends to aggressively pursue its exploration plan in
2000 while continuing to enhance its project inventory through its ongoing
acquisition of 3-D seismic-enhanced opportunities. It will also focus on any
potential merger or acquisition which it believes can enhance shareholder
value through expansion of exploration opportunities or increased economies of
scale.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company currently has no action filed against it other than
ordinary routine litigation.
ITEM 2. CHANGES IN SECURITIES.
In the six months ended June 30, 2000 and in the third quarter
through August 8, 2000, the Company has issued 39,135 and 8,356 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. It
also issued 84,000 shares of common stock comprised of 12,000 shares to each
of seven of its directors. The shares were part of an overall compensation
package for its directors, which package included stock options as further
described in Item 10 located at Part III of the Company's report on Form
10-KSB/A for the year ended December 31, 1999 dated April 28, 2000. The price
per share paid by Directors was $1.83 per share payable one third upon
subscription, one third on or before May 14, 2000 and one third on or before
May 15, 2001. The shares issued pursuant to the 401-K plan and to the
Directors are presently unregistered but are intended to be registered in 2000.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM 5. OTHER INFORMATION.
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits
(11) Computation of Earnings Per Common Share
(27.1) Financial Data Schedule
(b) Reports on Form 8-K
None.
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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 14, 2000 By: /s/ MICHAEL E. JOHNSON
--------------- ---------------------------------------
MICHAEL E. JOHNSON, President,
Chief Executive Officer and Director
Date: AUGUST 14, 2000 By: /s/ DAVID B. CHRISTOFFERSON
--------------- ---------------------------------------
DAVID B. CHRISTOFFERSON,
Senior Vice President, General Counsel,
Principal Financial Officer
Date: AUGUST 14, 2000 By: /s/ ANGELA D. CONWAY
--------------- ---------------------------------------
ANGELA D. CONWAY,
Controller
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