<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
/X/ QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SEPTEMBER 30, 2000
OR
/ / TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from.............. to .............
Commission file number 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0511037
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Texaco Heritage Plaza
1111 Bagby, Suite 2100
Houston, Texas 77002
(Address of principal executive offices)
(713) 654-8960
(Registrant's telephone number, including area code)
Indicate by checkmark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes _X_ No ___
Indicate the number of shares outstanding of each of the issuer's
classes of common equity, as of the latest practicable date.
CLASS OUTSTANDING AT NOVEMBER 10, 2000
Common Stock 9,186,908
<PAGE>
PART I. FINANCIAL INFORMATION
<TABLE>
<CAPTION>
ITEM 1. FINANCIAL STATEMENTS
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------------------------------------
September 30, December 31, 1999
2000
----------------- ----------------
(Unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,796,480 $ 577,864
Accounts receivable, trade 4,221,613 3,489,709
Accounts receivable, joint interest owners, net of allowance of $163,000 at
September 30, 2000 and December 31, 1999, respectively 375,466 1,177,555
Accounts receivable, related parties 27,610 59,951
Other current assets 211,139 161,558
----------------- ----------------
Total current assets 7,632,308 5,466,637
PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and natural
gas properties 44,523,364 45,976,007
INVESTMENT IN FRONTERA -- 3,867,233
OTHER ASSETS 7,788 7,788
----------------- ----------------
TOTAL ASSETS $ 52,163,460 $ 55,317,665
================= ================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 908,543 $ 1,332,760
Revenue payable 815,219 536,448
Accrued liabilities 1,043,015 4,458,481
Accrued interest payable 54,992 16,369
Current portion of long-term debt 2,550,000 4,100,000
----------------- ----------------
Total current liabilities 5,371,769 10,444,058
LONG-TERM DEBT 2,100,000 2,700,000
----------------- ----------------
Total liabilities 7,471,769 13,144,058
----------------- ----------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares authorized; none issued and
outstanding
Common stock, $0.01 par value; 25,000,000 shares authorized; 9,186,908 shares
and 9,182,023 shares issued and outstanding at September 30, 2000 and
December 31, 1999, respectively 91,869 91,820
Additional paid-in capital 55,252,004 55,223,901
Accumulated deficit (10,645,574) (13,107,890)
Unearned compensation - restricted stock (6,608) (34,224)
----------------- ----------------
Total stockholders' equity 44,691,691 42,173,607
----------------- ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 52,163,460 $ 55,317,665
================= ================
</TABLE>
See accompanying notes to consolidated financial statements.
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<PAGE>
<TABLE>
<CAPTION>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
---------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------------- -------------------------------------
2000 1999 2000 1999
--------------- --------------- ---------------- -----------------
<S> <C> <C> <C> <C>
OIL AND NATURAL GAS REVENUE $ 5,587,517 $ 3,055,912 $ 14,081,277 $ 10,787,549
OPERATING EXPENSES:
Lifting costs 391,358 396,254 1,403,320 1,362,624
Severance and ad valorem taxes 434,491 300,652 1,045,283 987,871
Depletion, depreciation and amortization 1,877,863 1,161,910 5,855,351 5,475,213
General and administrative expenses 985,400 976,612 2,875,337 3,076,371
Unearned compensation expense 8,590 124,842 25,768 292,795
--------------- --------------- ---------------- -----------------
Total operating expenses 3,697,702 2,960,270 11,205,059 11,194,874
--------------- --------------- ---------------- -----------------
OPERATING INCOME (LOSS) 1,889,815 95,642 2,876,218 (407,325)
OTHER INCOME AND EXPENSE:
Loss on sale of investment in Frontera -- -- (354,733) --
Interest income 34,294 18,106 61,164 43,817
Interest expense (29,655) (18,046) (120,333) (86,232)
--------------- --------------- ---------------- -----------------
INCOME (LOSS) BEFORE INCOME TAXES 1,894,454 95,702 2,462,316 (449,740)
INCOME TAX EXPENSE -- -- -- --
--------------- --------------- ---------------- -----------------
NET INCOME (LOSS) $ 1,894,454 $ 95,702 $ 2,462,316 $ (449,740)
=============== =============== ================ =================
BASIC EARNINGS (LOSS) PER SHARE $ 0.21 $ 0.01 $ 0.27 $ (0.05)
=============== =============== ================ =================
DILUTED EARNINGS (LOSS) PER SHARE $ 0.20 $ 0.01 $ 0.26 $ (0.05)
=============== =============== ================ =================
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 9,192,801 9,163,151 9,181,168 8,514,561
=============== =============== ================ =================
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 9,330,817 9,234,311 9,331,529 8,514,561
=============== =============== ================ =================
</TABLE>
See accompanying notes to consolidated financial statements.
-3-
<PAGE>
<TABLE>
<CAPTION>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)
------------------------------------------------------------------------------------------------------------------------------
Unearned
Common Stock Additional Compensation - Total
------------------------- Paid-in Accumulated Restricted Stockholders'
Shares Amount Capital Deficit Stock Equity
--------- ---------- ------------ ------------- -------------- -------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE,
JANUARY 1, 2000 9,182,023 $ 91,820 $ 55,223,901 $ (13,107,890) $ (34,224) $ 42,173,607
Forfeiture of restricted
stock (4,763) (47) (1,801) 1,848 --
Issuance of stock 9,648 96 29,904 30,000
Unearned compensation
expense 25,768 25,768
Net income 2,462,316 2,462,316
--------- ---------- ------------ ------------- ------------ ------------
BALANCE,
SEPTEMBER 30, 2000 9,186,908 $ 91,869 $ 55,252,004 $ (10,645,574) $ (6,608) $ 44,691,691
========= ========= ============ ============= ============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
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<PAGE>
<TABLE>
<CAPTION>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
----------------------------------------------------------------------------------------------------------------------
Nine Months Ended September 30,
-------------------------------
2000 1999
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 2,462,316 $ (449,740)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depletion, depreciation and amortization 5,855,351 5,475,213
Unearned compensation expense 25,768 292,795
Loss on sale of investment in Frontera 354,733 --
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, trade (731,904) 232,493
Decrease in accounts receivable, joint interest owners 802,089 1,555,451
Decrease in accounts receivable, related parties 32,341 22,853
(Increase) decrease in other current assets (49,581) 104,866
Decrease in accounts payable, trade (424,217) (1,198,032)
Increase (decrease) in revenue payable 278,771 (948,209)
Decrease in accrued liabilities (3,385,466) (341,654)
Increase (decrease) in accrued interest payable 38,623 (52,718)
------------ ------------
Net cash provided by operating activities 5,258,824 4,693,318
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment purchases (6,195,686) (11,269,850)
Proceeds from the sale of oil and natural gas properties and prospects 1,792,978 7,076,266
Proceeds from the sale of investment in Frontera 3,512,500 --
Investment in Frontera -- (122,297)
------------ ------------
Net cash used in investing activities (890,208) (4,315,881)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 850,000 3,600,000
Payments of long-term debt (3,000,000) (10,650,000)
Proceeds from private offering, net of offering cost -- 7,382,450
------------ ------------
Net cash provided by (used in) financing activities (2,150,000) 332,450
------------ ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 2,218,616 709,887
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 577,864 272,428
------------ ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 2,796,480 $ 982,315
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
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<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
--------------------------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements included herein have been prepared by Edge
Petroleum Corporation, a Delaware corporation ("we", "our", "us" or the
"Company"), without audit pursuant to the rules and regulations of the
Securities and Exchange Commission, and reflect all adjustments which are, in
the opinion of management, necessary to present a fair statement of the results
for the interim periods on a basis consistent with the annual audited
consolidated financial statements. All such adjustments are of a normal
recurring nature. The results of operations for the interim periods are not
necessarily indicative of the results to be expected for an entire year. Certain
information, accounting policies and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been omitted pursuant to such rules and regulations, although we
believe that the disclosures are adequate to make the information presented not
misleading. These financial statements should be read in conjunction with our
audited consolidated financial statements included in our Annual Report on Form
10-K for the year ended December 31, 1999.
ACCOUNTING PRONOUNCEMENTS
DERIVATIVES - In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS No. 133"). SFAS No. 133, as amended
by Statement of Financial Accounting Standards No. 138, "Accounting for
Derivative Instruments and Hedging Activities - an amendment to SFAS No. 133,"
issued in June 2000, establishes accounting and reporting standards for
derivative instruments and hedging activities that require an entity to
recognize all derivatives as an asset or liability measured at fair value.
Depending on the intended use of the derivatives, changes in its fair value will
be reported in the period of change as either a component of earnings or a
component of other comprehensive income.
In June 1999, the Financial Accounting Standards Board issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133" ("SFAS No. 137"). SFAS No. 137
delays the effective date for implementation of SFAS No. 133 for one year,
making SFAS No. 133 effective for all fiscal quarters of all fiscal years
beginning after June 15, 2000, or January 1, 2001 for the company. Retroactive
application to periods prior to adoption is not allowed. Currently, the Company
is not a party to any derivative instruments for future periods beyond December
31, 2000 and does not anticipate entering into any such agreements at this time.
If we enter into any such agreements, we will be required to recognize a related
asset or liability at January 1, 2001.
2. LONG TERM DEBT
EXISTING CREDIT FACILITY
At September 30, 2000, we were a party to a credit facility (the
"Revolving Credit Facility") with a bank. Borrowings under the Revolving Credit
Facility were limited by a borrowing base, as defined in the Revolving Credit
Facility, and bore interest at a rate equal to prime or LIBOR plus 1.75% to
2.75% depending upon the level of borrowing base utilization. The Revolving
Credit Facility was secured by substantially all of our assets.
At September 30, 2000, the borrowings under this facility totaled $4.65
million with no remaining borrowing base available for future borrowings. The
borrowing base was required to be reduced on the first day of each month by
$450,000; however, payments were deferred during the third quarter while we
negotiated our new credit facility as discussed below.
The Revolving Credit Facility provided for certain restrictions, including
but not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, engaging in
merger or consolidation transactions and prohibitions of dividends and certain
distributions of cash or properties and certain liens. The Revolving Credit
Facility also contained certain financial covenants. The Tangible Net Worth
Covenant required that at the end of each quarter our Tangible Net Worth be at
least 90% of our actual tangible net worth as reported at December 31, 1998 (or
$33,260,720) plus 50% of positive net income and 100% of other increases in
equity for all fiscal quarters ending subsequent to December 31, 1998. The Fixed
Charge Covenant required that at the end of each quarter beginning June 30,
1999, the ratio of annualized EBITDA (as defined) to the sum of annualized
interest expense plus 50% of the quarter end loans outstanding was at least 1.25
to 1.00. At September 30, 2000 and December 31, 1999 we were in compliance with
the above mentioned covenants.
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<PAGE>
NEW CREDIT FACILITY
In October 2000, we entered into a new credit facility (the "New Credit
Facility") with a new bank. Borrowings under the New Credit Facility are limited
by a borrowing base currently set at $5.0 million, as defined in the New Credit
Facility, and bear interest at a rate equal to prime or LIBOR. We borrowed $4.5
million under the new facility and repaid the $4.65 million outstanding under
the existing facility with a combination of borrowings and cash on hand. The New
Credit Facility is secured by substantially all of our assets.
The borrowing base under the New Credit Facility can be periodically
redetermined. The borrowing base is also subject to mandatory reductions, which
are subject to revision each time the borrowing base is redetermined. Reductions
to the borrowing base of $300,000 per month are required on the last day of each
month beginning February 28, 2001.
The New Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, engaging in
merger or consolidation transactions and prohibitions of dividends and certain
distributions of cash or properties and certain liens. The New Credit Facility
also contains certain financial covenants. The EBITDA to Interest Expense Ratio
requires that (a) consolidated EBITDA, as defined in the agreement, of the
parent for the four fiscal quarters then ended to (b) the consolidated interest
expense of the parent for the four fiscal quarters then ended, to not be less
than 3.5 to 1.0. The Working Capital covenant requires that the amount of the
parent's consolidated current assets less its consolidated liabilities, as
defined in the agreement, to be at least $1.0 million. The Allowable Expenses
ratio requires that (a) the aggregate amount of the parent's year to date
consolidated general and administrative expenses for the period from January 1
of such year through the fiscal quarter then ended to (b) the parent's year to
date consolidated net oil and gas revenues for the period from January 1 of such
year through the fiscal quarter then ended, to be less than .40 to 1.0.
The current portion of long-term debt as of September 30, 2000 is $2.55
million, reflecting these revisions in bank terms.
3. EARNINGS PER SHARE
We account for earnings per share in accordance with Statement of
Financial Accounting Standards No. 128 "Earnings per Share," ("SFAS No. 128")
which establishes the requirements for presenting earnings per share ("EPS").
SFAS No. 128 requires the presentation of "basic" and "diluted" EPS on the face
of the income statement. Basic earnings per common share amounts are calculated
using the average number of common shares outstanding during each period.
Diluted earnings per share assumes the exercise of all stock options and
warrants, having exercise prices less than the average market price of the
common stock during the periods, using the treasury stock method.
The following is presented as a reconciliation of the numerators and
denominators of basic and diluted earnings per share computations, in accordance
with SFAS No. 128.
<TABLE>
<CAPTION>
Three Months Ended September 30, 2000 Three Months Ended September 30, 1999
-------------------------------------------- -----------------------------------------------
Shares Per Shares
Income (Denomin- Share Income (Denomin- Per Share
(Numerator) ator) Amount Numerator ator) Amount
------------- ------------ ---------- --------------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
BASIC EPS
Income available to
common
stockholders $ 1,894,454 9,192,801 $ 0.21 $ 95,702 9,163,151 $ 0.01
Effect of Dilutive
Securities:
Restricted stock 138,016 --
Common stock
options -- 71,160
------------- ------------ ---------- --------------- ------------ -----------
DILUTED EPS
Income available to
common stockholders $ 1,894,454 9,330,817 $ 0.20 $ 95,702 9,234,311 $ 0.01
============= ============ ========== =============== ============ ===========
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
Nine Months Ended September 30, 2000 Nine Months Ended September 30, 1999
-------------------------------------------- -----------------------------------------------
Shares Per Income Shares
Income (Denomin- Share (Loss) (Denomin- Per Share
(Numerator) ator) Amount Numerator ator) Amount
------------- ------------ ---------- --------------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
BASIC EPS
Income (loss) available
to common
stockholders $ 2,462,316 9,181,168 $ 0.27 $ (449,740) 8,514,561 $ (0.05)
Effect of Dilutive
Securities:
Restricted stock 150,361
Common stock
options --
------------- ------------ ---------- --------------- ------------ -----------
DILUTED EPS
Income (loss) available
to common
stockholders $ 2,462,316 9,331,529 $ 0.26 $ (449,740) 8,514,561 $ (0.05)
============= ============ ========== =============== ============ ===========
</TABLE>
4. INCOME TAXES
Due to our significant deferred tax assets, no tax expense (benefit) was
recorded for the three-month or nine-month periods ended September 30, 2000 and
1999. Due to the uncertainty as to whether we will continue to be profitable in
the future, an allowance has been provided to offset the tax benefits of certain
tax assets. Should we continue to have net income in future periods, income tax
expense will be recorded upon utilization of available tax assets.
5. EQUITY
We account for Stock Based Compensation in accordance with Statement of
Financial Accounting Standards No. 123-"Accounting for Stock Based
Compensation," ("SFAS No. 123"). Under SFAS No. 123, we are permitted to
either record expense for stock options and other employee compensation plans
based on their fair value at the date of grant or to continue to apply our
current accounting policy under Accounting Principles Board Opinion No. 25
("APB No.25") and recognize compensation expense, if any, based on the
intrinsic value of the equity instrument at the measurement date. We have
elected to continue following APB No. 25.
Effective May 21, 1999, we amended and restated our Incentive Plan. In
conjunction with those and other amendments of the Incentive Plan, we exchanged,
on a voluntary basis, 556,488 outstanding nonqualified stock options of certain
employees and our Directors for 326,400 new common stock options in replacement
of those options. The exercise price of the replacement options was $7.06, which
represents the fair market value on the date of grant. The replacement options
have a ten-year term with 50% of the options vesting immediately on the date of
grant with the remaining 50% vesting on May 21, 2000. On May 21, 1999, we also
issued 114,350 new ten-year common stock options to employees, which vest 100%
on May 21, 2001. The exercise price of the new options was $7.06, which
represents the fair market value on the date of grant. On June 1, 1999, we
issued 21,000 ten-year common stock options to non-employee directors with an
exercise price of $7.28 per share, which represents the fair market value on the
date of grant, vesting 100% on June 1, 2001.
In March 2000, the Financial Accounting Standards Board issued FASB
Interpretation No. 44, "Accounting for Certain Transactions involving Stock
Compensation," an interpretation of APB No. 25. This Interpretation clarifies
the application of APB No. 25 for certain issues including (a) the definition of
"employee" for the purpose of applying APB No. 25, (b) the criteria for
determining whether a plan qualifies as noncompensatory, (c) the accounting
consequences of various modifications to the terms of previously fixed stock
options or awards and (d) the accounting for an exchange of stock compensation
awards in a business combination. This Interpretation is effective July 1, 2000,
but certain conclusions cover specific events occurring after December 15, 1998
or January 12, 2000. To the extent that this Interpretation covers events
occurring during the period after December 15, 1998 or January 12, 2000, but
before the effective date of July 1, 2000, the effects of applying this
Interpretation are recognized on a prospective basis from July 1, 2000. The
voluntary exchange and issuance of new common stock options, both in replacement
of existing options and as new grants, referred to above, which were effective
May 21, 1999 and June 1, 1999, will be covered by this Interpretation as these
transactions fall within the guidelines of a specific event after December 15,
1998 as defined by the Interpretation. Accordingly these new common stock
options will be accounted for under variable plan accounting on a prospective
basis from July 1, 2000, resulting in additional compensation expense in our
results of operations if the stock price increases above
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<PAGE>
the exercise price of the option. As of September 30, 2000, the exercise
price of all options was above the current stock price and no adjustment to
compensation expense was required.
In May 2000, the board approved the award of 161,300 shares of
restricted stock to certain employees effective March 2, 2000 for services to
be performed over the next three years. Shares of our common stock will be
issued for those services according to a vesting schedule of one third each
year following the anniversary date of the grant. Compensation expense will
be accrued in each period in which the services are performed based on the
quoted market price of our common stock as of the effective date of the
grant. For the nine months ended September 30, 2000 we accrued $107,700 in
compensation expense related to the future issuance of these shares of stock.
6. PROPERTY DISPOSITION
In April 2000, we completed the sale of our working interests in the
Wheeler property in Starr County, Texas. Proceeds from the sale were
approximately $1 million and associated net proved reserves were approximately
550 MMcfe or 2% of our total proved reserves, at the time of the sale.
We use the full-cost method of accounting for our oil and natural gas
properties. Under this method, a sale of oil and natural gas properties, whether
or not being amortized currently, are accounted for as an adjustment of
capitalized costs, with no gain or loss recognized unless such adjustment would
significantly alter the relationship between capitalized costs and proved
reserves. The proceeds from the sale of this proved producing property were
credited directly to the full cost pool.
7. SALE OF INVESTMENT IN FRONTERA
In June 2000, we sold our investment in Frontera for $3.6 million and
reported a loss on the sale of $354,733, or $(0.04) per share, in our results of
operations. Proceeds of $1.6 million and $2.0 million were received in June and
July, respectively, and we paid $87,500 for fees associated with the sale.
Proceeds from the sale were used to repay debt obligations on our existing
credit facility and for general corporate purposes.
8. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
We consider all highly liquid debt instruments purchased with an original
maturity of three months or less to be cash equivalents. A summary of non-cash
investing and financing activities for the nine months ended September 30, 2000
and 1999 is presented below:
In May 2000, a portion of the annual retainer due our directors was paid
by the issuance of 9,648 shares of common stock valued at $30,000, based on
quoted market prices on the date of issuance.
For the nine months ended September 30, 2000, forfeitures of restricted
stock were recorded with respect to 4,763 shares valued at $1,848.
In June 1999, a portion of the annual retainer due our directors was paid
by the issuance of 4,809 shares of common stock valued at $29,479, based on the
quoted market prices on the date of issuance.
For the nine months ended September 30, 1999, forfeitures of restricted
stock were recorded with respect to 325 shares valued at $4,024.
Supplemental Disclosure of Cash Flow Information
<TABLE>
<CAPTION>
For the Nine Months Ended
September 30,
-------------------------
2000 1999
--------- ---------
<S> <C> <C>
Cash paid during the period
for:
Interest, net of amounts
capitalized $106,499 $ 95,225
</TABLE>
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<PAGE>
9. HEDGING ACTIVITIES
Due to the instability of oil and natural gas prices, we enter into, from
time to time, price risk management transactions (e.g., swaps and collars) for a
portion of our oil and natural gas production in an effort to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements limits the benefit to us of increases in the
price of oil and natural gas it also limits the downside risk of adverse price
movements. Our hedging arrangements typically apply to only a portion of our
production, providing only partial price protection against declines in oil and
natural gas prices and limiting potential gains from future increases in prices.
We account for these transactions as hedging activities and, accordingly, gains
and losses are included in oil and natural gas revenues during the period the
hedged production occurs.
The impact on oil and natural gas revenues from hedging activities for the
nine months ended September 30, 2000 and 1999 was as follows:
<TABLE>
<CAPTION>
Loss
-----------------------------------
Nine Months Ended
Price Bbl MMBtu September 30,
Hedge Effective Dates Per Price Per Volumes Volumes -----------------------------------
Type Beg. Ending Barrel MMBtu Per Day Per Day 2000 1999
------------ -------- ---------- -------- ----------- ----------- ---------- ---------------- ---------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Natural Gas
Swap 3/1/99 10/31/99 $ 1.957 13,000 $ -- $ (861,631)
Natural Gas
Swap 4/1/99 9/15/99 $ 2.145 3,000 -- (154,124)
Natural Gas $ 2.20-
Collar 2/1/00 2/29/00 $ 2.31 9,000 (70,470)
Natural Gas $ 2.20-
Collar 3/1/00 4/30/00 $ 2.50 9,000 (135,900)
Natural Gas $ 2.05-
Collar 5/1/00 9/30/00 $ 2.60 6,000 (1,342,320)
Oil Swap 1/1/00 3/31/00 $25.60 150 (27,521)
Oil Swap 4/1/00 6/30/00 $22.87 125 (55,481)
Oil Swap 7/1/00 9/30/00 $21.47 60 (65,796)
---------------- ---------------
Total $ (1,697,488) $ (1,015,755)
================ ===============
</TABLE>
Our hedging activities for natural gas are entered into on a per MMbtu
delivered price basis, Houston Ship Channel, with settlement for each calendar
month occurring five business days following the publishing of the Inside
F.E.R.C. Gas Marketing Report.
Included within oil and natural gas revenues for the nine months ended
September 30, 2000 and 1999 were $(1,697,488) and $(1,015,755), respectively,
representing net losses from hedging activity. During December 1999, we entered
into a crude oil fixed price swap. The number of barrels of oil per day ("BOD")
and the related fixed price subject to the oil price swap are as follows: i)
January 1, 2000 - March 31, 2000, 150 BOD, swap at $25.60, ii) April 1, 2000 -
June 30, 2000, 125 BOD, swap at $22.87, iii) July 1, 2000 - September 30, 2000,
60 BOD, swap at $21.47, and iv) October 1, 2000 - December 31, 2000, 50 BOD,
swap at $ 20.46. During the first quarter of 2000 we entered into three natural
gas collars. The natural gas collars cover the following periods, MMbtu per day
and floor and ceiling per MMbtu prices: i) February 1, 2000 - February 29, 2000,
9,000 MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March 1, 2000 - April 30,
2000, 9,000 MMbtu per day, $2.20 floor - $2.50 ceiling and iii) May 1, 2000 -
September 30, 2000, 6,000 MMbtu per day, $2.05 floor - $2.60 ceiling. At
September 30, 2000 and December 31, 1999, the market value of outstanding hedges
was approximately $(68,500) and $15,000, respectively.
10. COMMITMENTS AND CONTINGENCIES
From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. The Company is not currently a
party to any litigation that it believes could have a material adverse effect
on the financial position of the Company, except for the litigation described
below.
The Company, as one of three plaintiffs, has filed a lawsuit against
BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company,
LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial
District Court of Duval County, Texas, for fraud and breach of contract in
connection with an agreement whereby BNP was obligated to drill a test well
in an area known as the Slick Prospect in Duval County, Texas. The
allegations of the Company in this litigation are, in general, that BNP gave
the Company inaccurate and incomplete information on which the Company relied
in making its decision not to participate in the test well and the prospect,
resulting in the loss of the Company's interest in the lease, the test well
and four subsequent wells drilled in the prospect. The Company seeks to
enforce its approximate 23% interest in the prospect and seeks damages or
rescission, as well as costs and attorneys' fees. The case was originally
filed in Duval County, Texas on February 25, 2000.
In mid March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations and exemplary damages.
The case proceeded to trial before the Court (without a jury) on June 19,
2000, after the plaintiffs' were found by the court to have failed to comply
with procedural requirements regarding the request for a jury. After several
days of trial, the case was recessed and later resumed on September 5, 2000.
The court at that time denied the plaintiffs' motion for mistrial based on
the court's denial of a jury trial. The court also ordered that the
defendants' counterclaims would be the subject of a separate trial that is to
commence on December 11, 2000. The parties proceeded to try issues related
to the plaintiffs' claims on September 5, 2000. All parties rested on the
plaintiffs' claims on September 13, 2000. The court took the matter under
advisement and has not yet announced a ruling. Defendants had filed a second
amended answer and counterclaim and certain supplemental responses to a
request for disclosure in which they stated that they were seeking damages in
the amount of $33.5 million by virtue of an alleged lost sale of the subject
properties, $17 million in alleged lost profits from other prospective
contracts, and unspecified incidental and consequential damages from the
alleged wrongful suspension of funds under their gas sales contract with the
gas purchaser on the properties, alleged damage to relationships with trade
creditors and financial institutions, including the inability to leverage the
Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval
County, Texas incurred in defending against plaintiffs' claims and for 40% of
any aggregate recovery in prosecuting their counterclaims. In subsequent
deposition testimony, the defendants have verbally alleged $26 million of
damages by virtue of the alleged lost sale of the properties (as opposed to
the $33.5 million previously sought), $7.5 million of damages by virtue of
loss of a lease development opportunity and $100 million of damages by virtue
of the loss of a business opportunity related to BNP's alleged inability to
participate in a 3-D seismic project.
A dispositive motion for summary judgment on all of BNP's counterclaims
for monetary damages has been filed and is set for a hearing on November 29,
2000. If that motion is denied, in whole or in part, the Company will
proceed to trial on the counterclaims on December 11, 2000. While the
Company believes it has sufficient legal defenses to all of the defendants'
counterclaims, and intends to vigorously defend itself in this matter, there
can be no assurance that the outcome of any portion of this litigation will
be favorable to the Company. In the possible event of a material adverse
outcome on the counterclaims or related matters, there would be a material
adverse effect on the Company as the Company would likely be required to post
a bond in the amount of the judgment (or the portion of the counterclaim
judgment for which it has liability) in order to prevent the defendants from
executing on that judgment. Depending on the amount of such a judgment,
there could be no assurance that the Company could obtain such a bond. In
the event of an adverse judgment, the Company would likely appeal such
judgment, and the Company is optimistic about its chances for success on
appeal, should such be necessary.
The Company also alleged that BNP Petroleum Corporation, Seiskin
Interests, LTD and Pagenergy Company, LLC breached a contract with the
plaintiffs by obtaining oil and gas leases within an area restricted by that
contract. While this breach of contract allegation is the subject of an
additional lawsuit by plaintiffs in the 165th District Court in Harris
County, Texas, the defendants have taken the position that the claim must be
tried in the Duval County case. The Duval County court has taken that
question under advisement and might rule that the claim should be included in
the December 11, 2000 trial. The Company is seeking damages as a result of
defendants' actions as well as costs and attorneys' fees, and the defendants
are seeking a declaration of no liability in this matter.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following is management's discussion and analysis of certain
significant factors that have affected certain aspects of our financial
position and operating results during the periods included in the accompanying
unaudited condensed consolidated financial statements. This discussion should
be read in conjunction with the accompanying unaudited condensed consolidated
financial statements included elsewhere in this Form 10-Q and with our audited
consolidated financial statements included in our annual report on Form 10-K
for the year ended December 31, 1999.
OVERVIEW
The following matters had a significant impact on our results of
operations and financial position for the nine months ended September 30, 2000:
COMMODITY PRICES - The average realized price for our production, before
the effects of hedging activity, increased 61% from $2.18 per thousand cubic
feet of gas equivalent (Mcfe) in the first nine months of 1999 to $3.50 per
Mcfe for the comparable period this year. Hedging activity for the nine months
ended September 30, 2000 resulted in a net loss of approximately $1.7 million,
or $0.38 per Mcfe, compared to a net loss of approximately $1.0 million, or
$0.19 per Mcfe, for the same period in 1999.
SALE OF INVESTMENT IN FRONTERA - In June 2000, we sold our investment in
Frontera for $3.6 million and reported a loss on the sale of $354,733, or
$0.04 per share, in our results of operations.
DEBT REDUCTION - Our current credit facility requires our borrowing base
to be reduced $450,000 on the first day of each month. In addition, the sale
in April 2000 of certain of our oil and natural gas properties resulted in a
further reduction of our borrowing base. During the nine months ended
September 30, 2000, we borrowed $850,000 (in January 2000) and repaid $3.0
million. At September 30, 2000, borrowings under this facility totaled $4.65
million with no remaining borrowing base available for future borrowings. In
October 2000, we entered into a new credit facility with a new bank in the
principal amount of $4.5 million, repaid the $4.65 million under our existing
facility and terminated that facility. Payments due under the old facility
were deferred during the third quarter while we negotiated our new facility.
Borrowings under the new facility are limited by a borrowing base as defined
in the credit agreement, and bear interest at a rate equal to prime or LIBOR.
The borrowing base is subject to monthly mandatory reductions of $300,000
beginning February 28, 2001.
RESULTS OF OPERATIONS
REVENUE AND PRODUCTION
Oil and natural gas revenues for the third quarter of 2000 increased 83%
over the same period in 1999. Natural gas production comprised 83% of total
production on an equivalent Mcf basis and contributed 82% of total revenue for
the third quarter of 2000. Oil and condensate production was 8% of total
production and contributed 10% of total oil and gas revenue while natural gas
liquids (NGLs) production comprised 9% of total production and contributed
8% of total oil and gas revenue. In the comparable 1999 period, natural gas
production and revenue comprised 80% of total production and 74% of total oil
and gas revenue while oil and condensate production was 9% of total production
and 15% of revenue and NGLs production comprised 11% of total production and
11% of revenue.
For the nine months ended September 30, 2000, oil and natural gas
revenues increased 31% over the same period in 1999. Natural gas production
comprised 80% of total production and contributed 78% of total revenue, oil
and condensate comprised 10% of total production and contributed 13% of total
oil and gas revenue, and NGLs production comprised 10% of total production and
contributed 9% of total oil and gas revenue. For the same period in 1999,
natural gas production comprised 84% of total production and 82% of total oil
and gas revenue while oil and condensate production accounted for 10% of total
production and 12% revenue and NGLs production comprised 6% of both total
production and revenue.
The following table summarizes volume and price information with respect
to our oil and gas production for the quarter and nine-month periods ended
September 30, 2000 and 1999:
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<TABLE>
<CAPTION>
For the Quarter For the Nine Months
Ended September 30, Ended September 30,
--------------------------------------- ---------------------------------------
Increase Increase
2000 1999 (Decrease) 2000 1999 (Decrease)
--------- --------- ------------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Gas Volume - MCFGPD (1) 13,636 13,230 406 13,227 16,651 (3,424)
Average Gas Price - per MCF $ 4.39 $ 2.59 $ 1.80 $ 3.46 $ 2.17 $ 1.29
Hedge Loss - per MCF $ (0.74) $ (0.74) -- $ (0.43) $ (0.22) $ (0.21)
Oil and Condensate Volume - BPD (2) 227 244 (17) 264 334 (70)
Average Oil Price - per barrel $ 29.67 $ 19.94 $ 9.73 $ 26.78 $ 14.71 $ 12.07
Hedge Loss - per barrel $ (3.16) -- $ (3.16) $ (2.06) -- $ (2.06)
Natural Gas Liquids Volume - BPD (2) 247 302 (55) 277 206 71
Average NGL Price - per barrel $ 20.17 $ 12.73 $ 7.44 $ 17.23 $ 10.77 $ 6.46
</TABLE>
----------------------------
(1) MCFGPD - thousand cubic feet of gas per day
(2) BPD - barrels per day
THIRD QUARTER 2000 COMPARED TO THE THIRD QUARTER 1999
Natural gas sales revenue increased 103%, from $2.3 million for the
third quarter of 1999 to approximately $4.6 million for the same period in
2000. The impact of favorable natural gas prices and a slight increase in
production was partially offset by the effect of hedging activity. The average
realized price for natural gas production, excluding the effect of hedging
activity, was $4.39 per Mcf for the third quarter of 2000, an increase of 69%
over the 1999 third quarter average price of $2.59 per Mcf. This increase in
average prices favorably impacted revenues by approximately $2.3 million
(based on current quarter production). Included within natural gas revenues
for the three months ended September 30, 2000 was $(932,640) representing
losses from hedging activities. These losses decreased the effective natural
gas price by $(0.74) per Mcf for the third quarter of 2000. For the same
period in 1999, gas hedging activities resulted in a loss of $(899,568) and
decreased the effective natural gas sales price for that prior period by
$(0.74) per Mcf. Production volumes for natural gas for the three months ended
September 30, 2000 increased 3% from 13,230 MCFGPD for the third quarter of
1999 to 13,636 MCFGPD for the comparable period in 2000. This slight increase
in natural gas production during the third quarter of 2000 increased revenues
by $96,775 (based on 1999 comparable quarter average prices). The increase was
due to production from 18 gross (6.322073 net) new successful exploratory and
development wells drilled and completed since September 30, 1999. Offsetting
the favorable impact of new production was a decrease in production volumes
that resulted from the disposition of certain proved producing properties
effective July 1, 1999 and April 1, 2000, further reduced by normal production
declines from existing wells.
Revenue from sales of oil and condensate increased 23% from $448,131 in
the third quarter of 1999 to approximately $552,568 for the comparable 2000
period due primarily to higher average realized prices. The average realized
price for oil and condensate in the third quarter of 2000 was $29.67 per
barrel, excluding the impact of net oil hedging losses of $3.16 per barrel,
compared to $19.94 per barrel for the same period in 1999. This increase in
the average realized price received for our oil and condensate increased
revenue $202,774 (based on current quarter production). Production volumes for
oil and condensate decreased 7% from 244 BPD in the third quarter of 1999 to
227 BPD for the comparable period in 2000. This slight decrease in production
decreased quarterly revenues $32,541 (based on 1999 comparable quarter average
prices).
Revenue from sales of natural gas liquids (NGLs) increased 29% from
$353,916 in the third quarter of 1999 to $457,822 for the comparable 2000
period due primarily to higher average realized prices, partially offset by
lower production. The average realized price for NGLs in the third quarter of
2000 was $20.17 per barrel compared to $12.73 per barrel for the same period
in 1999. This
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increase in the average realized price received for our NGLs increased revenue
$168,892 (based on current quarter production). Production volumes for NGLs
decreased 18% from 302 BPD in the third quarter of 1999 to 247 BPD for the
comparable period in 2000. This decrease in production decreased quarterly
revenues $64,986 (based on 1999 comparable quarter average prices).
YEAR-TO-DATE 2000 COMPARED TO YEAR-TO-DATE 1999
Natural gas revenue increased 24%, from $8.8 million for the nine months
ended September 30, 1999 to approximately $11.0 million in the same current
year period due to the impact of favorable average realized prices, partially
offset by the negative impact of hedging losses and decreased production. The
average natural gas sales price for production in the first nine months of
2000 was $3.46 per Mcf, exclusive of the hedging activity, compared to $2.17
per Mcf during the same prior year period. This increase in average price
realized resulted in increased revenues of approximately $4.7 million (based
on current year-to-date production). Included within natural gas revenue for
the nine months ended September 30, 2000 and 1999 was $(1.5) million and
$(1.0) million, respectively, representing losses on hedging activity. These
losses decreased the effective natural gas sales price by $(0.43) per Mcf and
$(0.22) per Mcf for the nine months ended September 30, 2000 and 1999,
respectively. The favorable impact of higher average prices was partially
offset by the impact of lower production. For the nine months ended September
30, natural gas production decreased 21% from 16,651 MCFPD in 1999 to 13,227
MCFPD in 2000 resulting in a decrease in revenues of $2.0 million (based on
1999 comparable period prices).
Revenue from the sale of oil and condensate totaled $1.8 million for the
nine months ended September 30, 2000 (including net losses from oil hedge
activity of $148,798), an increase of 33% from the prior year nine-month total
of $1.3 million. Favorable pricing for the first nine months of 2000 resulted
in an increase in revenue of $873,950 (based on current year-to-date
production). The average realized price for oil and condensate in the first
nine months of 2000 was $26.78 per barrel, excluding the impact of net oil
hedging losses of $(2.06) per barrel, compared to $14.71 per barrel for the
same period in 1999. Production volumes for oil and condensate for the nine
months ended September 30, 2000 decreased 21% from 334 BPD to 264 BPD, as
compared to the nine months ended September 30, 1999. The decrease in oil and
condensate production decreased revenues by $276,317 (based on 1999 comparable
period average prices).
Revenue from the sale of NGLs totaled $1.3 million for the nine months
ended September 30, 2000, an increase of 116% from the prior year nine-month
total of $604,935. Favorable pricing for the first nine months of 2000
resulted in an increase in revenue of $703,051 (based on current year-to-date
production). The average realized price for NGLs in the first nine months of
2000 was $17.23 per barrel compared to $10.77 per barrel for the same period
in 1999. Production volumes for NGLs for the nine months ended September 30,
2000 increased 34% from 206 BPD to 277 BPD, as compared to the nine months
ended September 30, 1999. The increase in NGL production increased revenues by
$212,897 (based on 1999 comparable period average prices).
Year-to-date production of oil and natural gas was significantly
impacted by the sale of certain oil and natural gas properties effective July
1, 1999 and April 1, 2000. Offsetting these declines was the adjustment in
June 2000 for 19 months of revenue associated with pay-out on our McFaddin
properties totaling $391,300 on production of 173,800 Mcfe. In addition, we
successfully drilled and completed 18 gross (6.32 net) wells since September
30, 1999 that added additional production and revenues for the current year
period.
COSTS AND OPERATING EXPENSES
Lifting costs for the three-month period ended September 30, 2000
totaled $391,358, a slight decrease compared to the same period in 1999. For
the nine months ended September 30, 2000, lifting costs totaled $1,403,320
compared to $1,362,624 in the same period of 1999, an increase of 3%. Current
year results were impacted by the recording of 19 months of lifting costs
totaling approximately $119,000, associated with our McFaddin properties that
reached pay-out in July 1998 but was not determined until June 2000. These
additional costs more than offset the effect of lower costs resulting from the
disposition of proved producing properties effective July 1, 1999, and
corporate efforts focused on improving the operating structure in the field.
Lifting costs were $0.26 per Mcfe for the three-month periods ended September
30, 2000 and 1999, respectively. For the year-to-date periods, lifting costs
were $0.31 per Mcfe in 2000 and $0.25 per Mcfe for 1999. Excluding the
adjustment for the above-mentioned property, lifting costs were $0.30 for the
nine-month period ended September 30, 2000. The increase in lifting costs on a
Mcfe basis was due to the sale of certain properties during the third quarter
of 1999 that had lower overall average lifting costs.
Severance and ad valorem taxes for the three months ended September 30,
2000 increased 44% from $300,652 to $434,491 as compared to the three months
ended September 30, 1999 due primarily to higher severance taxes paid on the
increased revenue during the third quarter of 2000. Severance and ad valorem
taxes were $0.29 per Mcfe and $0.20 per Mcfe for the three-month periods ended
September 30, 2000 and 1999, respectively. For the nine months ended September
30, 2000 and 1999, severance and
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ad valorem taxes totaled $1,045,283 and $987,871, respectively. On an
equivalent basis, severance and ad valorem taxes were $0.23 per Mcfe and $0.18
for the nine months ended September 30, 2000 and 1999, respectively.
Depletion, depreciation and amortization expense ("DD&A") expense for
the third quarter and nine-month periods ended September 30, 2000 totaled $1.9
million and $5.9 million, respectively, compared to $1.2 million and $5.5
million in the comparable 1999 periods. Full cost DD&A on our oil and natural
gas properties totaled $1.7 million for the third quarter of 2000 and $5.3
million for the nine months ended September 30, 2000 compared to $1.0 million
for the third quarter of 1999 and $4.9 million for the year-to-date period in
1999. Depletion expense on a unit of production basis for the three-month
periods ended September 30, 2000 and 1999 was $1.13 per Mcfe and $0.65 per
Mcfe, respectively. For the nine months ended September 30, 2000, DD&A totaled
$1.18 per Mcfe, 30% higher than the year-to-date 1999 rate of $0.91 per Mcfe.
For the third quarter of 2000 a 72% increase in the overall depletion rate
increased depletion expense by $716,600 while lower oil and natural gas
production compared to the prior year period decreased depletion expense by
only $2,000. For the year-to-date period, lower oil and natural gas production
compared to the same prior year period decreased depletion expense by $833,900
and a 30% increase in the overall depletion rate increased depletion expense
by $1.2 million. The increase in the depletion rate was primarily attributable
to the abandonment of certain properties during the fourth quarter of 1999.
Other DD&A expense of $169,652 for the three-month period ended September 30,
2000 was slightly higher than the prior year total of $168,251 in the same
period of 1999. Year-to-date, other DD&A decreased four-percent from $530,239
in 1999 to $508,871 for the comparable nine-month period ended September 30,
2000. The decrease in other DD&A was due primarily to the amortization of
deferred loan costs on the Revolving Credit Facility on which amortization
began April 1, 1998 and was fully amortized at March 31, 1999.
General and administrative expenses ("G&A") for the third quarter of
2000 increased 1% from $976,612 to $985,400, as compared to the three months
ended September 30, 1999. The slight increase in G&A was primarily
attributable to compensation expense related to restricted stock awarded in
March 2000 offset by lower salaries and related benefits attributable to a
work force reduction during January 2000. G&A expense for the nine-month
period ended September 30, 2000 totaled $2.9 million, a decrease of 7% from
the $3.1 million incurred during the nine months ended September 30, 1999. For
the third quarter of 2000 and 1999, overhead reimbursement fees recorded as a
reduction to G&A totaled $29,352 and $65,000, respectively. For the nine
months ended September 30, 2000 and 1999, overhead reimbursement fees reduced
G&A by approximately $92,300 and $240,000, respectively. G&A on a unit of
production basis for the three-month periods ended September 30, 2000 and 1999
was $0.65 per Mcfe and $0.64 per Mcfe, respectively. For the year-to-date
periods ended September 30, 2000 and 1999, G&A on a unit of production basis
was $0.64 per Mcfe and $0.57 per Mcfe, respectively.
Unearned compensation expense for the three months ended September 30,
2000 decreased from $124,842 to $8,590, as compared to the three months ended
September 30, 1999. For the nine months ended September 30, 2000, unearned
compensation expense totaled $25,768 compared to $292,795 in the comparable
prior year period. The decrease is due to the resignation of the former
President and Chief Operating Officer during December 1999 whereby he vested
in his remaining restricted stock grant. The Company charged to expense his
unamortized unearned compensation upon his resignation, thereby reducing the
future amounts to be charged to income.
Other income (expense) for the nine-month period ending September 30,
2000 consisted primarily of a loss on the sale of our investment in Frontera
of $(354,733), or $(0.04) per share.
Also included in other income (expense) was interest expense of $29,655
for the third quarter of 2000 compared to $18,046 in the third quarter of
1999. Gross interest expense was $114,220 for the third quarter of 2000 on
weighted average debt of approximately $4.6 million compared to gross interest
expense of $121,292 on weighted average debt of approximately $6.4 million for
the same prior year period. Capitalized interest in the third quarter of 2000
totaled $84,565 compared to $103,246 in the third quarter of 1999. For the
year-to-date period ended September 30, 2000, interest expense totaled
$120,333, an increase of 40% over the prior year period total of $86,232.
Weighted average debt was approximately $6.0 million for the nine months ended
September 30, 2000, resulting in gross interest costs of $439,827. For the
same period in 1999, weighted average debt of $9.1 million resulted in gross
interest costs of $535,760. Capitalized interest for the nine months ended
September 30, 2000 totaled $319,494, a decrease of 29% over the prior year
amount of $449,528 for the same period. Although gross interest expense has
decreased compared to the prior year, the effect of less interest being
capitalized to oil and natural gas properties has resulted in higher net
interest costs reported in our results of operations. The reduction in
capitalized interest resulted from lower exploration activities during the
three and nine-month periods ended September 30, 2000 compared to the same
periods in the prior year.
Interest income totaled $34,294 for the three months ended September 30,
2000 and $61,164 for the 2000 year-to-date period compared to $18,106 and
$43,817 in the respective prior year periods. The increase in interest income
is due to the overall increase in invested overnight money market funds.
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Due to our significant deferred tax assets, no tax expense (benefit) was
recorded for the three-month or nine-month periods ended September 30, 2000
and 1999. Due to the uncertainty as to whether we will be profitable in the
future, an allowance has been provided to offset the tax benefits of certain
tax assets. Should we continue to have net income in future periods, income
tax expense will be recorded upon utilization of available tax assets.
For the third quarter of 2000, we reported net income of $1,894,454, or
$0.21 basic earnings per share, compared to net income of $95,702, or $0.01
basic earnings per share, for the same period in 1999. For the nine months
ended September 30, 2000, we reported net income of $2,462,316, or $0.27 basic
earnings per share, compared to a net loss of $(449,740), or $(0.05) basic
loss per share, in the comparable 1999 period. Weighted average shares
outstanding increased from approximately 8.5 million for the nine months ended
September 30, 1999 to 9.2 million in the comparable 2000 period. The increase
was due primarily to the private placement of 1.4 million shares of common
stock in May 1999.
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash needs are for exploration, development and acquisition
of oil and gas properties, and repayment of principal and interest on
outstanding debt. Due to our active exploration and development and technology
enhancement programs, we have experienced and expect to continue to experience
substantial working capital requirements. We intend to fund our remaining 2000
capital expenditures, commitments and working capital requirements through
cash flows from operations and the refinancing of our existing Revolving
Credit Facility. Our new facility, completed in October 2000, has an increased
borrowing base with monthly commitment reductions that are lower than our
current facility requirements and are deferred until February 28, 2001. We
believe we will be able to generate capital resources and liquidity sufficient
to fund our capital expenditures and meet our financial obligations as they
come due. In the event such capital resources are not available to us, our
drilling and other activities may be curtailed. Currently, our expected cash
flow from operations for the remainder of 2000 exceeds our planned capital
spending for the same period.
LIQUIDITY
We had cash and cash equivalents at September 30, 2000 of $2.8 million
consisting primarily of short-term money market investments, as compared to
$577,864 at December 31, 1999. Our working capital surplus was $2,260,539 at
September 30, 2000, as compared to a deficit of $(4,977,421) at December 31,
1999 and our ratio of current assets to current liabilities was 1.42:1 at
September 30, 2000 compared to 0.52:1 at December 31, 1999. Excluding the
current portion of long-term debt, we had a working capital surplus of
$4,810,539 at September 30, 2000, as compared to a working capital deficit of
$(877,421) at December 31, 1999. Our ratio of current assets to current
liabilities excluding the current portion of long-term debt was 2.70:1 at
September 30, 2000 compared to 0.86:1 at December 31, 1999. Our working
capital surplus and increased current ratio at September 30, 2000 resulted
primarily from a decrease in accounts payable and accrued liabilities.
Proceeds from the sale of our investment in Frontera were used to reduce our
debt outstanding and to pay down our accounts payable balances while the
decrease in accrued liabilities resulted from the settlement with industry
partners of revenues held in suspense.
CASH FLOWS
Cash flows provided by operations were $5.3 million and $4.7 million for
the nine months ended September 30, 2000 and 1999, respectively. The increase
in cash flows provided by operations for the nine months ended September 30,
2000 is primarily due to net income in the current year as compared to a net
loss in the prior year, offset by changes in working capital. During the nine
months ended September 30, 2000, net working capital usage was $3.1 million as
compared to $645,520 for the same period in 1999. Current year activity was
impacted by a significant decrease in accrued liabilities as a result of
settling disputed amounts with an industry partner during the second quarter
of 2000 and releasing certain amounts held in suspense. Operating cash flows,
before changes in working capital, were $8.7 million and $5.3 million for the
nine months ended September 30, 2000 and 1999, respectively. Operating cash
flow should not be considered in isolation or as a substitute for net income,
operating income, cash flows from operating activities or any other measure of
financial performance presented in accordance with generally accepted
accounting principles or as a measure of profitability or liquidity.
Cash used in investing activities totaled $890,208 for the nine months
ended September 30, 2000 compared to $4.3 million used in the same period of
1999. During the nine months ended September 30, 2000, we continued to
reinvest a substantial portion of our cash flows to fund our drilling
program. Capital expenditures during the nine months ended September 30, 2000
were approximately $6.2 million as compared to $11.3 million during the same
period in 1999. We expended $3.9 million in our drilling operations resulting
in the drilling of 14 gross (4.81 net) wells during the nine months ended
September 30, 2000 as compared to 7 gross (3.78 net) wells during the same
period in 1999. We currently have five gross wells drilling. The remaining
cost capitalized to oil and natural gas properties was
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capitalized internal G&G and interest of approximately $1.4 million. Total
capital expenditures for 2000 are expected to be approximately $10.0 million.
Other investing activity also included proceeds from the sale of oil and
natural gas properties of approximately $1.8 million for the nine months ended
September 30, 2000 and proceeds from the sale of our investment in Frontera of
$3.6 million less associated fees of $87,500. For the nine months ended
September 30, 1999, we had proceeds from the sale of oil and natural gas
properties of $7.1 million offset by expenditures on our investment in
Frontera of $122,297.
Cash used in financing activities totaled $2.15 million for the nine
months ended September 30, 2000 and included borrowings under our credit
facility of $850,000 and repayments of $3.0 million. For the nine months ended
September 30, 1999, cash provided by financing activities totaled $332,450 and
included net repayments of $7.05 million. In addition, we received proceeds
from a private offering totaling $7.4 million, net of offering costs, in May
of 1999.
CREDIT FACILITY
EXISTING CREDIT FACILITY
At September 30, 2000, we were a party to a credit facility (the
"Revolving Credit Facility") with a bank. Borrowings under the Revolving
Credit Facility were limited by a borrowing base, as defined in the Revolving
Credit Facility, and bore interest at a rate equal to prime or LIBOR plus
1.75% to 2.75% depending upon the level of borrowing base utilization. The
Revolving Credit Facility was secured by substantially all of our assets. At
September 30, 2000, the borrowings under this facility totaled $4.65 million
with no remaining borrowing base available for future borrowings. The
borrowing base was required to be reduced on the first day of each month by
$450,000; however, payments were deferred during the third quarter while we
negotiated our new credit facility as discussed below.
NEW CREDIT FACILITY
In October 2000, we entered into a new credit facility (the "New Credit
Facility") with a new bank. Borrowings under the New Credit Facility are
limited by a borrowing base currently set at $5.0 million, as defined in the
New Credit Facility, and bear interest at a rate equal to prime or LIBOR. We
borrowed $4.5 million under the new facility and repaid the $4.65 million
outstanding under the existing facility with a combination of borrowings and
cash on hand. The New Credit Facility is secured by substantially all of our
assets.
The borrowing base under the New Credit Facility can be periodically
redetermined. The borrowing base is also subject to mandatory reductions,
which are subject to revision each time the borrowing base is redetermined.
Reductions to the borrowing base of $300,000 per month are required on the
last day of each month beginning February 28, 2001.
The New Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, engaging
in merger or consolidation transactions and prohibitions of dividends and
certain distributions of cash or properties and certain liens. The New Credit
Facility also contains certain financial covenants. The EBITDA to Interest
Expense Ratio requires that (a) consolidated EBITDA, as defined in the
agreement, of the parent for the four fiscal quarters then ended to (b) the
consolidated interest expense of the parent for the four fiscal quarters then
ended, to not be less than 3.5 to 1.0. The Working Capital covenant requires
that the amount of the parent's consolidated current assets less its
consolidated liabilities, as defined in the agreement, to be at least $1.0
million. The Allowable Expenses ratio requires that (a) the aggregate amount
of the parent's year to date consolidated general and administrative expenses
for the period from January 1 of such year through the fiscal quarter then
ended to (b) the parent's year to date consolidated net oil and gas revenues
for the period from January 1 of such year through the fiscal quarter then
ended, to be less than .40 to 1.0.
ACCOUNTING PRONOUNCEMENTS
DERIVATIVES - In June 1998, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS No. 133"). SFAS No. 133,
as amended by Statement of Financial Accounting Standards No. 138, "Accounting
for Derivative Instruments and Hedging Activities - an amendment to SFAS No.
133," issued in June 2000, establishes accounting and reporting standards for
derivative instruments and hedging activities that require an entity to
recognize all derivatives as an asset or liability measured at fair value.
Depending on the intended use of the derivatives, changes in its fair value
will be reported in the period of change as either a component of earnings or
a component of other comprehensive income.
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<PAGE>
In June 1999, the Financial Accounting Standards Board issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral
of the Effective Date of FASB Statement No. 133" ("SFAS No. 137"). SFAS No.
137 delays the effective date for implementation of SFAS No. 133 for one year,
making SFAS No. 133 effective for all fiscal quarters of all fiscal years
beginning after June 15, 2000, or January 1, 2001 for the company. Retroactive
application to periods prior to adoption is not allowed. Currently, the
Company is not a party to any derivative instruments for future periods beyond
December 31, 2000 and does not anticipate entering into any such agreements at
this time. If we enter into any such agreements, we will be required to
recognize a related asset or liability at January 1, 2001.
In March 2000, the Financial Accounting Standards Board issued FASB
Interpretation No. 44, "Accounting for Certain Transactions involving Stock
Compensation," an interpretation of APB No. 25. This Interpretation clarifies
the application of APB No. 25 for certain issues including (a) the definition
of "employee" for the purpose of applying APB No. 25, (b) the criteria for
determining whether a plan qualifies as noncompensatory, (c) the accounting
consequences of various modifications to the terms of previously fixed stock
options or awards and (d) the accounting for an exchange of stock compensation
awards in a business combination. This Interpretation is effective July 1,
2000, but certain conclusions cover specific events occurring after December
15, 1998 or January 12, 2000. To the extent that this Interpretation covers
events occurring during the period after December 15, 1998 or January 12,
2000, but before the effective date of July 1, 2000, the effects of applying
this Interpretation are recognized on a prospective basis from July 1, 2000.
The voluntary exchange and issuance of new common stock options both in
replacement of existing options and as new grants, referred to in Note 5,
which were effective May 21, 1999 and June 1, 1999, will be covered by this
Interpretation as these transactions fall within the guidelines of a specific
event after December 15, 1998 as defined by the Interpretation. Accordingly
these new common stock options will be accounted for under variable plan
accounting on a prospective basis from July 1, 2000, resulting in an effect on
our results of operations for increases in the stock price above the exercise
price of the option. As of September 30, 2000, the exercise price of all
options was above the current stock price and no adjustment to compensation
expense was required.
FORWARD LOOKING STATEMENTS
The statements contained in all parts of this document, including, but
not limited to, those relating to our drilling plans, our 3-D project
portfolio, capital expenditures, future capabilities, the sufficiency of
capital resources and liquidity to support working capital and capital
expenditure requirements, reinvestment of cash flows, the outcome of
litigation, and any other statements regarding future operations, financial
results, business plans, sources of liquidity and cash needs and other
statements that are not historical facts are forward looking statements. When
used in this document, the words "anticipate," "estimate," "expect," "may,"
"project," "believe" and similar expressions are intended to be among the
statements that identify forward looking statements. Such statements involve
risks and uncertainties, including, but not limited to, those relating to our
dependence on our exploratory drilling activities, the volatility of oil and
natural gas prices, the need to replace reserves depleted by production,
operating risks of oil and natural gas operations, our dependence on key
personnel, our reliance on technological development and possible obsolescence
of the technology currently used by us, significant capital requirements of
our exploration and development and technology development programs, the
potential impact of government regulations, litigation and environmental
matters, our ability to manage our growth and achieve our business strategy,
competition, the uncertainty of reserve information and future net revenue
estimates, property acquisition risks and other factors detailed in our Form
10-K and other filings with the Securities and Exchange Commission. Should one
or more of these risks or uncertainties materialize, or should underlying
assumptions prove incorrect, actual outcomes may vary materially from those
indicated.
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<PAGE>
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk from changes in interest rates and commodity
prices. We use a Revolving Credit Facility, which has a floating interest
rate, to finance a portion of our operations. We are not subject to fair value
risk resulting from changes in our floating interest rates. The use of
floating rate debt instruments provides a benefit due to downward interest
rate movements but does not limit us to exposure from future increases in
interest rates. Based on the September 30, 2000 floating interest rate of 9.5%
and the amount of debt outstanding on that date, a 10% change in the interest
rate would result in an increase or decrease in interest expense of
approximately $42,000 on an annual basis. In the normal course of business we
enter into hedging transactions, including commodity price collars and swaps,
to mitigate our exposure to commodity price movements, but not for trading or
speculative purposes. During the nine months ended September 30, 2000, due to
the instability of oil prices and to achieve a more predictable cash flow, we
had in place a fixed price oil swap for a portion of our year 2000 oil and
condensate production. While the use of these arrangements limits the benefit
to us of increases in the price of oil and natural gas it also limits the
downside risk of adverse price movements. The number of barrels of oil per day
("BOD") and the related fixed price subject to the oil price swap are as
follows: i) January 1, 2000 - March 31, 2000, 150 BOD, swap at $25.60, ii)
April 1, 2000 - June 30, 2000, 125 BOD, swap at $22.87, iii) July 1, 2000 -
September 30, 2000, 60 BOD, swap at $21.47 and iv) October 1, 2000 - December
31, 2000, 50 BOD, swap at $20.46. A 10% change in the oil price per barrel
would cause the total market value of the swap to increase or decrease by
approximately $9,400. During the nine months ended September 30, 2000, due to
the instability of natural gas prices and to achieve a more predictable cash
flow, we had in place three natural gas collars for a portion of our year 2000
natural gas production. The natural gas collars cover the following periods,
MMbtu per day and floor and ceiling per MMbtu prices: i) February 1, 2000 -
February 29, 2000, 9,000 MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March
1, 2000 - April 30, 2000, 9,000 MMbtu per day, $2.20 floor -$2.50 ceiling and
iii) May 1, 2000 - September 30, 2000, 6,000 MMbtu per day, $2.05 floor -
$2.60 ceiling. Currently, there are no natural gas collars in place for any
future periods. At September 30, 2000, the market value of the outstanding
hedge was approximately $(68,500).
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<PAGE>
PART II - OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS
From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. The Company is not currently a
party to any litigation that it believes could have a material adverse effect
on the financial position of the Company, except for the litigation described
below.
The Company, as one of three plaintiffs, has filed a lawsuit against
BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company,
LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial
District Court of Duval County, Texas, for fraud and breach of contract in
connection with an agreement whereby BNP was obligated to drill a test well
in an area known as the Slick Prospect in Duval County, Texas. The
allegations of the Company in this litigation are, in general, that BNP gave
the Company inaccurate and incomplete information on which the Company relied
in making its decision not to participate in the test well and the prospect,
resulting in the loss of the Company's interest in the lease, the test well
and four subsequent wells drilled in the prospect. The Company seeks to
enforce its approximate 23% interest in the prospect and seeks damages or
rescission, as well as costs and attorneys' fees. The case was originally
filed in Duval County, Texas on February 25, 2000.
In mid March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations and exemplary damages.
The case proceeded to trial before the Court (without a jury) on June 19,
2000, after the plaintiffs' were found by the court to have failed to comply
with procedural requirements regarding the request for a jury. After several
days of trial, the case was recessed and later resumed on September 5, 2000.
The court at that time denied the plaintiffs' motion for mistrial based on
the court's denial of a jury trial. The court also ordered that the
defendants' counterclaims would be the subject of a separate trial that is to
commence on December 11, 2000. The parties proceeded to try issues related
to the plaintiffs' claims on September 5, 2000. All parties rested on the
plaintiffs' claims on September 13, 2000. The court took the matter under
advisement and has not yet announced a ruling. Defendants had filed a second
amended answer and counterclaim and certain supplemental responses to a
request for disclosure in which they stated that they were seeking damages in
the amount of $33.5 million by virtue of an alleged lost sale of the subject
properties, $17 million in alleged lost profits from other prospective
contracts, and unspecified incidental and consequential damages from the
alleged wrongful suspension of funds under their gas sales contract with the
gas purchaser on the properties, alleged damage to relationships with trade
creditors and financial institutions, including the inability to leverage the
Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval
County, Texas incurred in defending against plaintiffs' claims and for 40% of
any aggregate recovery in prosecuting their counterclaims. In subsequent
deposition testimony, the defendants have verbally alleged $26 million of
damages by virtue of the alleged lost sale of the properties (as opposed to
the $33.5 million previously sought), $7.5 million of damages by virtue of
loss of a lease development opportunity and $100 million of damages by virtue
of the loss of a business opportunity related to BNP's alleged inability to
participate in a 3-D seismic project.
A dispositive motion for summary judgment on all of BNP's counterclaims
for monetary damages has been filed and is set for a hearing on November 29,
2000. If that motion is denied, in whole or in part, the Company will
proceed to trial on the counterclaims on December 11, 2000. While the
Company believes it has sufficient legal defenses to all of the defendants'
counterclaims, and intends to vigorously defend itself in this matter, there
can be no assurance that the outcome of any portion of this litigation will
be favorable to the Company. In the possible event of a material adverse
outcome on the counterclaims or related matters, there would be a material
adverse effect on the Company as the Company would likely be required to post
a bond in the amount of the judgment (or the portion of the counterclaim
judgment for which it has liability) in order to prevent the defendants from
executing on that judgment. Depending on the amount of such a judgment,
there could be no assurance that the Company could obtain such a bond. In
the event of an adverse judgment, the Company would likely appeal such
judgment, and the Company is optimistic about its chances for success on
appeal, should such be necessary.
The Company also alleged that BNP Petroleum Corporation, Seiskin
Interests, LTD and Pagenergy Company, LLC breached a contract with the
plaintiffs by obtaining oil and gas leases within an area restricted by that
contract. While this breach of contract allegation is the subject of an
additional lawsuit by plaintiffs in the 165th District Court in Harris
County, Texas, the defendants have taken the position that the claim must be
tried in the Duval County case. The Duval County court has taken that
question under advisement and might rule that the claim should be included in
the December 11, 2000 trial. The Company is seeking damages as a result of
defendants' actions as well as costs and attorneys' fees, and the defendants
are seeking a declaration of no liability in this matter.
<TABLE>
<S> <C>
ITEM 2 - CHANGES IN SECURITIES AND USE OF PROCEEDS............................. None
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
</TABLE>
(A) EXHIBITS. The following exhibits are filed as part of this report:
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit No.
--------------
<S> <C>
+2.1 -- Amended and Restated Combination Agreement by and among (i)
Edge Group II Limited Partnership, (ii) Gulfedge Limited
Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum
Corporation, (v) Edge Mergeco, Inc. and (vi) the Company,
dated as of January 13, 1997 (Incorporated by reference from
exhibit 2.1 to the Company's Registration Statement on Form
S-4 (Registration No. 333-17269))
+3.1 -- Restated Certificate of Incorporated of the Company, as
amended (Incorporated by reference from exhibit 3.1 to the
Company's Registration Statement on Form S-4 (Registration No.
333-17269)).
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<PAGE>
+3.2 -- Bylaws of the Company. (Incorporated by Reference from
exhibit 3.3 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended September 30, 1999).
+3.3 -- First Amendment to Bylaws of the Company on September 28,
1999 (Incorporated by Reference from exhibit 3.2 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
+4.1 -- Amended and Restated Credit Agreement, dated April 1, 1998,
by and between Edge Petroleum Corporation and Edge Petroleum
Exploration Company (collectively the "Borrower") and Compass
Bank, a Texas state chartered banking institution, as Agent
for itself and First National Bank of Chicago and other
lenders party thereto. (Incorporated by Reference from exhibit
4.1 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 1998).
+4.2 -- First Amendment dated September 29, 1998 to the Amended and
Restated Credit Agreement, dated as of April 1, 1998, by and
between the Borrower and the First National Bank of Chicago as
agent and a Lender thereto (Incorporated by Reference from
exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended March 31, 1998).
+4.3 -- Security Agreement, dated as of April 1, 1998, by and
between the Borrower and Compass Bank, a Texas state chartered
banking institution, as Agent for itself and The First
National Bank of Chicago and other lenders party thereto the
Credit Agreement (Incorporated by Reference from exhibit 4.1
to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended March 31, 1998).
+4.4 -- Security Agreement (Stock Pledge), dated as of April 1,
1998, by and between Edge Petroleum Corporation and Compass
Bank, a Texas state chartered banking institution, as Agent
for itself and The First National Bank of Chicago and other
lenders party thereto the Credit Agreement (Incorporated by
Reference from exhibit 4.1 to the Company's Quarterly Report
on Form 10-Q for the quarterly period ended March 31, 1998).
*4.5 -- Second Amended and Restated Credit Agreement dated October
6, 2000 by and between Edge Petroleum Corporation, Edge
Petroleum Exploration Company and Edge Petroleum Operating
Company, Inc. (collectively, the "Borrowers") and Union Bank
Of California, N.A., a national banking association, as Agent
for itself and as lender.
*4.6 -- Letter Agreement dated October 31, 2000 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender
-- The Company is a party to several debt instruments under
which the total amount of securities authorized does not
exceed 10% of the total assets of the Company and its
subsidiaries on a consolidated basis. Pursuant to paragraph
4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees
to furnish a copy of such instruments to the Commission upon
request.
+4.7 -- Common Stock Subscription Agreement dated as of April 30,
1999 between the Company and the purchasers named therein
(Incorporated by reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).
+4.8 -- Warrant agreement dated as of May 6, 1999 between the
Company and the Warrant holders named therein (Incorporated by
reference from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q/A for the quarter ended March 31, 1999).
+4.9 -- Form of Warrant for the purchase of the Common Stock
(Incorporated by reference from the Common Stock Subscription
Agreement from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q/A for the quarter ended March 31, 1999).
+10.1 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership II, dated as of May 10, 1994
(Incorporated by reference from exhibit 10.2 to the Company's
Registration Statement on Form S-4 (Registration No.
333-17269)).
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<PAGE>
+10.2 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership, dated as of April 11, 1992
(Incorporated by reference from exhibit 10.3 to the Company's
Registration Statement on Form S-4 (Registration No.
333-17269)).
+10.3 -- Form of Indemnification Agreement between the Company and
each of its directors (Incorporated by reference from exhibit
10.7 to the Company's Registration Statement on Form S-4
(Registration No. 333-17269)).
+10.4 -- Consulting Agreement of James C. Calaway dated March 18,
1989 (Incorporated by reference from exhibit 10.12 to the
Company's Registration Statement on Form S-4 (Registration No.
333-17269)).
+10.5 -- Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation (Incorporated by reference from exhibit 10.13 to
the Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
+10.6 -- Employment Agreement dated as of November 16, 1998, by and
between the Company and John W. Elias. (Incorporated by
reference from 10.12 to the Company's Annual Report on Form
10-K for the year ended December 31, 1998).
+10.7 -- Agreement dated as of November 16, 1998 by and between the
Company and John E. Calaway. (Incorporated by reference from
exhibit 10.13 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998).
+10.8 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of July 27, 1999. (Incorporated by
reference from exhibit 10.1 to the Company's Quarterly Report
on Form 10-Q for the quarterly period ended September 30,
1999).
+10.9 -- Edge Petroleum Corporation Incentive Plan "Standard
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Officers named therein.
(Incorporated by reference from exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.10 -- Edge Petroleum Corporation Incentive Plan "Director
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Directors named therein.
(Incorporated by reference from exhibit 10.3 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.11 -- Severance Agreements by and between Edge Petroleum
Corporation and the Officers of the Company named therein.
(Incorporated by reference from exhibit 10.4 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.12 -- Severance Agreement dated as of December 17, 1999 by and
between Edge Petroleum Corporation and James D. Calaway.
(Incorporated by reference from exhibit 10.13 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1999).
+10.13 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated by
Reference from exhibit 10.15 to the Company's Quarterly Report
on Form 10-Q/A for the quarterly period ended March 31, 1999).
+10.14 -- Form of Employee Restricted Stock Award Agreement between
the Company and James D. Calaway under the Incentive Plan of
Edge Petroleum Corporation (Incorporated by Reference from
exhibit 10.18 to the Company's Quarterly Report on Form 10-Q/A
for the quarterly period ended March 31, 1999).
+10.15 -- Letter agreement dated November 9, 1999 for the purchase
and sale of working interests in oil and natural gas
properties between the Company and James C. Calaway.
(Incorporated by reference from exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1999).
27.1 -- Financial Data Schedule.
</TABLE>
* Filed herewith.
+ Incorporated by reference as indicated.
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(B) Reports on Form 8-K
The Company filed with the Securities and Exchange Commission during the
quarter ended September 30, 2000, a Current Report on Form 8-K dated July 3,
2000, which reported the status of litigation to which the Company is one of
three plaintiffs.
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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 by the
undersigned thereunto duly authorized.
EDGE PETROLEUM CORPORATION,
A DELAWARE CORPORATION
(REGISTRANT)
Date 8/14/00 /s/ John W. Elias
-------------------------- --------------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board
Date 8/14/00 /s/ Michael G. Long
-------------------------- --------------------------------------
Michael G. Long
Senior Vice President and
Chief Financial Officer
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