<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 JUNE 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 August 11, 2000
----- ------------------------------
Common Stock 9,186,908
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------
June 30, December 31,
2000 1999
----------------- ----------------
(Unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,130,086 $ 577,864
Accounts receivable, trade 4,289,834 3,489,709
Accounts receivable, joint interest owners, net of allowance of $163,000 at
June 30, 2000 and December 31, 1999, respectively 296,014 1,177,555
Accounts receivable, related parties 37,610 59,951
Other current assets 2,187,517 161,558
----------------- ----------------
Total current assets 7,941,061 5,466,637
PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and natural
gas properties 43,734,047 45,976,007
INVESTMENT IN FRONTERA -- 3,867,233
OTHER ASSETS 7,788 7,788
----------------- ----------------
TOTAL ASSETS $ 51,682,896 $ 55,317,665
================= ================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 1,279,008 $ 1,332,760
Revenue payable 720,453 536,448
Accrued liabilities 2,228,419 4,458,481
Accrued interest payable 16,369 16,369
Current portion of long-term debt 4,050,000 4,100,000
----------------- ----------------
Total current liabilities 8,294,249 10,444,058
LONG-TERM DEBT 600,000 2,700,000
----------------- ----------------
Total liabilities 8,894,249 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 June 30, 2000 and December
31, 1999, respectively 91,869 91,820
Additional paid-in capital 55,252,004 55,223,901
Accumulated deficit (12,540,028) (13,107,890)
Unearned compensation - restricted stock (15,198) (34,224)
----------------- ----------------
Total stockholders' equity 42,788,647 42,173,607
----------------- ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 51,682,896 $ 55,317,665
================= ================
</TABLE>
See accompanying notes to consolidated financial statements.
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EDGE PETROLEUM CORPORATION
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>
OIL AND NATURAL GAS REVENUE $ 4,682,839 $ 4,189,449 $ 8,493,760 $ 7,731,637
OPERATING EXPENSES:
Lifting costs 572,153 487,242 1,011,962 966,370
Severance and ad valorem taxes 304,143 334,530 610,792 687,219
Depletion, depreciation and amortization 2,190,510 2,410,543 3,977,488 4,313,303
General and administrative expenses 1,011,158 1,097,939 1,889,937 2,099,758
Unearned compensation expense 8,589 83,977 17,178 167,953
--------------- --------------- --------------- ----------------
Total operating expenses 4,086,553 4,414,231 7,507,357 8,234,603
--------------- --------------- --------------- ----------------
OPERATING INCOME (LOSS) 596,286 (224,782) 986,403 (502,966)
OTHER INCOME AND EXPENSE:
Loss on sale of investment in Frontera (354,733) -- (354,733) --
Interest income 13,637 14,689 26,870 25,711
Interest expense (46,599) (29,860) (90,678) (68,186)
--------------- --------------- --------------- ----------------
INCOME (LOSS) BEFORE INCOME TAXES 208,591 (239,953) 567,862 (545,441)
INCOME TAX EXPENSE -- -- -- --
--------------- --------------- --------------- ----------------
NET INCOME (LOSS) $ 208,591 $ (239,953) $ 567,862 $ (545,441)
=============== =============== =============== ================
BASIC EARNINGS (LOSS) PER SHARE $ 0.02 $ (0.03) $ 0.06 $ (0.07)
=============== =============== =============== ================
DILUTED EARNINGS (LOSS) PER SHARE $ 0.02 $ (0.03) $ 0.06 $ (0.07)
=============== =============== =============== ================
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 9,192,801 8,589,312 9,191,794 8,176,223
=============== =============== =============== ================
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 9,192,801 8,589,312 9,191,794 8,176,223
=============== =============== =============== ================
</TABLE>
See accompanying notes to consolidated financial statements.
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EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------------
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 17,178 17,178
Net income 567,862 567,862
----------- ----------- --------------- ----------------- ---------------- ----------------
BALANCE, JUNE 30, 2000 9,186,908 $ 91,869 $ 55,252,004 $ (12,540,028) $ (15,198) $ 42,788,647
=========== =========== =============== ================= ================ ================
</TABLE>
See accompanying notes to consolidated financial statements.
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EDGE PETROLEUM CORPORATION
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) $ 567,862 $ (545,441)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depletion, depreciation and amortization 3,977,488 4,313,303
Unearned compensation expense 17,178 167,953
Loss on sale of investment in Frontera 354,733 --
Changes in assets and liabilities:
Increase in accounts receivable, trade (800,125) (448,737)
Decrease in accounts receivable, joint interest owners 881,541 1,218,865
Decrease in accounts receivable, related parties 22,341 21,063
(Increase) decrease in other current assets (25,959) 65,363
Decrease in accounts payable, trade (53,752) (1,492,369)
Increase (decrease) in revenue payable 184,005 (882,099)
Decrease in accrued liabilities (2,287,562) (286,794)
Increase (decrease) in accrued interest payable -- (38,724)
---------------- ----------------
Net cash provided by operating activities 2,837,750 2,092,383
---------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment purchases (3,498,572) (5,487,573)
Proceeds from the sale of oil and natural gas properties and prospects 1,763,044 1,648,719
Proceeds from the sale of investment in Frontera 1,600,000 --
Investment in Frontera -- (122,297)
---------------- ----------------
Net cash used in investing activities (135,528) (3,961,151)
---------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 850,000 1,000,000
Payments of long-term debt (3,000,000) (6,350,000)
Proceeds from private offering, net of offering cost -- 7,382,450
---------------- ----------------
Net cash provided by (used in) financing activities (2,150,000) 2,032,450
---------------- ----------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 552,222 163,682
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 577,864 272,428
---------------- ----------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 1,130,086 $ 436,110
================ ================
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized $ 78,310 $ 68,584
================ ================
</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. We are
in the process of analyzing the impact of adoption on our financial
statements, as well as any additional disclosure requirements.
2. LONG TERM DEBT
We are a party to a credit facility (the "Revolving Credit Facility")
with a bank. Borrowings under the Revolving Credit Facility are limited by a
borrowing base, as defined in the Revolving Credit Facility, and bear
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 is
secured by substantially all of our assets.
Each quarter, at our election or at the election of the bank, the
borrowing base under the Revolving Credit Facility can be redetermined. The
borrowing base is also subject to mandatory reductions, which are subject to
revision each time the borrowing base is redetermined. The borrowing base is
currently required to be reduced on the first day of each month by $450,000.
In April 2000, we sold certain oil and natural gas properties (see Note 6),
that caused an additional reduction in our borrowing base. At June 30, 2000,
the borrowings under this facility totaled $4.65 million with no remaining
borrowing base available for future borrowings. For the six months ended June
30, 2000, the weighted average debt outstanding was $6.7 million and the
weighted-average interest rate was 9.71%.
The Revolving 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 Revolving Credit Facility also contains certain financial
covenants. The Tangible Net Worth Covenant requires 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 requires
that at the end of each quarter beginning June 30, 1999, the ratio of
annualized EBITDA (as defined) to
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the sum of annualized interest expense plus 50% of the quarter end loans
outstanding must be at least 1.25 to 1.00. At June 30, 2000 and December 31,
1999 we were in compliance with the above mentioned covenants.
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. For the six months ended June 30, 2000 and 1999 all common stock
options and warrants were anti-dilutive.
4. INCOME TAXES
Due to our significant deferred tax assets, no tax expense (benefit)
was recorded for the three-month or six-month periods ended June 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.
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 326,700 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 99,800 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 the exercise price of
the option.
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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 were received in June and the balance of
$2.0 was recorded as a receivable. In addition, we recorded an accrued liability
of $87,500 for fees associated with the sale. The receivable was collected and
the fees were paid in July 2000. Proceeds from the sale were used to repay debt
obligations on our existing credit facility and for general corporate purposes.
8. NON-CASH INVESTING AND FINANCING ACTIVITIES
Supplemental Disclosure of Cash Flow Information
We consider all highly liquid debt instruments purchased with an original
maturity of three months or less to be cash equivalents.
In connection with the sale of our investment in Frontera, we recorded a
receivable for $2.0 million of the proceeds that was received subsequent to June
30, 2000. Additionally, we recorded an accrued liability of $87,500 for fees
associated with the sale that was paid subsequent to June 30, 2000.
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.
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
six months ended June 30, 2000 and 1999 was as follows:
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<TABLE>
<CAPTION>
Gain (Loss)
-----------------------------
Price Bbl MMBtu Six Months Ended June 30,
Effective Dates Per Price Per Volumes Volumes -----------------------------
Hedge 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 $ -- $ (116,188)
Natural Gas
Collar 2/1/00 2/29/00 $2.20-$2.31 9,000 (70,470)
Natural Gas
Collar 3/1/00 4/30/00 $2.20-$2.50 9,000 (135,900)
Natural Gas
Collar 5/1/00 9/30/00 $2.05- $2.60 6,000 (409,680)
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)
------------ -----------
Total $ (699,052) $ (116,188)
============ ===========
</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 six months ended June
30, 2000 and 1999 were $(699,052) and $(116,188), 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 June 30, 2000 and
December 31, 1999, the market value of outstanding hedges was approximately
$(1.1) million and $15,000, respectively.
10. SUBSEQUENT EVENTS
On July 19, 2000, we filed a Report on Form 8-K with the Securities and
Exchange Commission describing our litigation in the 229th Judicial District
Court of Duval County, Texas, to which we are a party.
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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 six months ended June 30, 2000:
COMMODITY PRICES - The average realized price for our production, before
the effects of hedging activity, increased 53% from $2.01 per thousand cubic
feet of gas equivalent (Mcfe) in the first six months of 1999 to $3.07 per Mcfe
for the comparable period this year. Hedging activity for the six months ended
June 30, 2000 resulted in a net loss of $699,052, or $0.23 per Mcfe, compared to
a net loss of $116,188, or $0.03 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. Proceeds of $1.6 million were received
in June 2000 and the balance of $2.0 million was recorded as a receivable at
June 30, 2000. The receivable was collected in July 2000.
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 six months ended June 30,
2000, we borrowed $850,000 (in January 2000) and repaid $3.0 million. At June
30, 2000, borrowings under this facility totaled $4.65 million with no remaining
borrowing base available for future borrowings.
RESULTS OF OPERATIONS
REVENUE AND PRODUCTION
Oil and natural gas revenues for the second quarter of 2000 increased 12%
over the same period in 1999. Natural gas production comprised 79% of total
production on an equivalent Mcf basis and contributed 77% of total revenues for
the second quarter of 2000 while oil, condensate and liquids ("liquids")
production was 21% of total production and contributed 23% of total oil and gas
revenue. In the comparable 1999 period, natural gas production and revenue
comprised 82% of both total production and revenue while liquids was 18% of both
total production and revenue.
For the six months ended June 30, 2000, oil and natural gas revenues
increased 10% over the same period in 1999. Natural gas production comprised 79%
of total production and contributed 75% of total revenue while liquids comprised
21% of total production and contributed 25% of total oil and gas revenue. For
the same period in 1999, natural gas production comprised 85% of both total
production and revenue while liquids accounted for 15% 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 six-month periods ended June
30, 2000 and 1999:
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<TABLE>
<CAPTION>
For the Quarter For the Six Months
Ended June 30, Ended June 30,
--------------------------------------- ---------------------------------------
Increase Increase
2000 1999 (Decrease) 2000 1999 (Decrease)
--------- --------- ------------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Gas Volume - MCFGPD (1) 13,994 18,245 (4,251) 13,021 18,391 (5,370)
Average Gas Price - per MCF $ 3.25 $ 2.22 $ 1.03 $ 2.96 $ 2.01 $ 0.95
Hedge Loss - per MCF $ (0.41) $ (0.16) $ (0.25) $ (0.26) $ (0.03) $ (0.23)
Liquids Volume - BOPD (2)(3) 612 655 (43) 576 536 40
Average Liquids Price - per barrel $ 20.00 $ 12.87 $ 7.13 $ 20.71 $ 11.78 $ 8.93
Hedge Loss - per barrel $ (1.00) -- $ (1.00) $ (0.79) -- $ (0.79)
</TABLE>
----------------------------------------------------
(1) MCFGPD - thousand cubic feet of gas per day
(2) BOPD - barrels of oil per day
(3) Liquids include crude oil, condensate and natural gas liquids (NGLs).
SECOND QUARTER 2000 COMPARED TO THE SECOND QUARTER 1999
Natural gas sales revenue increased six percent, from $3.4 million for the
second quarter of 1999 to approximately $3.6 million for the same period in
2000. The impact of favorable natural gas prices was partially offset by the
effect of hedging activity and decreased production. Included within natural gas
revenues for the three months ended June 30, 2000 was $(517,680) representing
losses from hedging activities. These losses decreased the effective natural gas
price by $(0.41) per Mcf for the second quarter of 2000. For the same period in
1999, gas hedging activities resulted in a loss of $(258,534) and decreased the
effective natural gas sales price for that prior period by $(0.16) per Mcf. The
average realized price for natural gas production, excluding the effect of
hedging activity, was $3.25 per Mcf for the second quarter of 2000, an increase
of 46% over the 1999 second quarter average price of $2.22 per Mcf. This
increase in average prices favorably impacted revenues by approximately $1.3
million (based on current quarter production). Production volumes for natural
gas for the three months ended June 30, 2000 decreased 23% from 18,245 MCFGPD
for the second quarter of 1999 to 13,994 MCFGPD for the comparable period in
2000. This decline in natural gas production during the second quarter of 2000
decreased revenues by $857,600 (based on 1999 comparable quarter average
prices). The decrease in production volumes was due primarily to the disposition
of certain proved producing properties effective July 1, 1999 and April 1, 2000,
further reduced by normal production declines from existing wells. Partially
offsetting these declines was production from 11 gross (3.41 net) new successful
exploratory and development wells drilled and completed since June 30, 1999. In
addition, pay-out from our McFaddin properties occurred in July 1998 but was not
determined until June 2000. We recorded 19 months of gas production in June 2000
for total natural gas revenue of $273,500 on production of 124,900 Mcf related
to these properties.
Revenue from sales of liquids increased 38% from $767,402 in the second quarter
of 1999 to approximately $1.1 million for the comparable 2000 period due
primarily to higher average realized prices. The average realized price for
liquids in the second quarter of 2000 was $20.00 per barrel, excluding the
impact of net oil hedging losses of $1.00 per barrel, compared to $12.87 per
barrel for the same period in 1999. This increase in the average realized price
received for our liquids increased revenue $397,600 (based on current quarter
production). Production volumes for liquids decreased 7% from 655 BOPD in the
second quarter of 1999 to 612 BOPD for the comparable period in 2000. This
slight decrease in production decreased quarterly revenues $50,300 (based on
1999 comparable quarter average prices). Included in liquids revenue for the
second quarter of 2000 is $117,800 on production of 8,150 barrels related to the
McFaddin properties discussed in the previous paragraph.
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YEAR-TO-DATE 2000 COMPARED TO YEAR-TO-DATE 1999
Natural gas revenue decreased three percent, from $6.6 million for the six
months ended June 30, 1999 to $6.4 million in the same current year period due
to the negative effect of hedging activity and decreased production, partially
offset by favorable average realized prices. Included within natural gas revenue
for the six months ended June 30, 2000 and 1999 was $(616,052) and $(116,188),
respectively, representing losses on hedging activity. These losses decreased
the effective natural gas sales price by $(0.26) per Mcf and $(0.03) per Mcf for
the six months ended June 30, 2000 and 1999, respectively. The average natural
gas sales price for production in the first half of 2000 was $2.96 per Mcf,
exclusive of the hedging activity, compared to $2.01 per Mcf during the same
prior year period. This increase in average price realized resulted in increased
revenues of approximately $2.2 million (based on current year-to-date
production). The favorable impact of higher average prices was almost completely
offset by the impact of lower production. For the six months ended June 30,
2000, natural gas production decreased 29% from 18,391 MCFPD to 13,021 MCFPD
resulting in a decrease in revenues of $1.9 million (based on 1999 comparable
period prices).
Revenue from the sale of liquids totaled $2.1 million for the six months ended
June 30, 2000 (including net losses from oil hedge activity of $83,002), an
increase of 83% from the prior year six-month total of $1.1 million. Favorable
pricing for the first six months of 2000 resulted in an increase in revenue of
$935,700 (based on current year-to-date production). The average realized price
for liquids in the first half of 2000 was $20.71 per barrel, excluding the
impact of net oil hedging losses of $(0.79) per barrel, compared to $11.78 per
barrel for the same period in 1999. Production volumes for liquids for the six
months ended June 30, 2000 increased 7% from 536 BOPD to 576 BOPD, as compared
to the six months ended June 30, 1999. The increase in liquid production
increased revenues by $90,900 (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 11 gross (3.41 net) wells since June 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 June 30, 2000 totaled
$572,153, an increase of 17% compared to the same period in 1999. For the six
months ended June 30, 2000, lifting costs totaled approximately $1.0 million
compared to $966,370 in the same period of 1999, an increase of 5%. 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 mitigated the effect of lower costs associated with 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
$0.36 per Mcfe and $0.24 per Mcfe for the three-month periods ended June 30,
2000 and 1999, respectively. For the year-to-date periods, lifting costs were
$0.34 per Mcfe in 2000 and $0.25 per Mcfe for 1999. Excluding the adjustment for
the above-mentioned property, lifting costs were $0.32 for the second quarter
and six-month periods ended June 30, 2000, respectively. 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 June 30, 2000
decreased 9% from $334,530 to $304,143 as compared to the three months ended
June 30, 1999 due primarily to higher severance taxes paid during the second
quarter of 1999. Severance and ad valorem taxes were $0.19 per Mcfe and $0.17
per Mcfe for the three-month periods ended June 30, 2000 and 1999, respectively.
For the six months ended June 30, 2000 and 1999, severance and ad valorem taxes
totaled $610,792 and $687,219, respectively. On an equivalent basis, severance
and ad valorem taxes were $0.20 per Mcfe and $0.18 for the six months ended June
30, 2000 and 1999, respectively.
Depletion, depreciation and amortization expense ("DD&A") expense for the
second quarter and six-month periods ended June 30, 2000 totaled $2.2 million
and $4.0 million, respectively, compared to $2.4 million and $4.3 million in the
comparable 1999 periods. Full cost DD&A on our oil and natural gas properties
totaled $2.0 million for the second quarter of 2000 and $3.6 million for the six
months ended June 30, 2000 compared to $2.2 million for the second quarter of
1999 and $3.9 million for the year-to-date period in 1999. Depletion expense on
a unit of production basis for the three-month periods ended June 30, 2000 and
1999 was $1.26 per Mcfe and $1.11 per Mcfe, respectively. For the six months
ended June 30, 2000, DD&A totaled $1.21 per Mcfe, 20% higher than the
year-to-date 1999 rate of $1.01 per Mcfe. For the second quarter of 2000, lower
oil and natural gas production compared to the prior year period decreased
depletion expense by $456,000 and a 13% increase in the overall depletion rate
increased depletion expense by $233,900. For the year-to-date period, lower oil
and natural gas production compared to the same prior year period decreased
depletion expense by $922,000 and a 20% increase in the overall depletion rate
increased depletion expense by $609,000. The increase in the depletion rate was
primarily attributable to the abandonment of certain properties during the
fourth quarter of
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1999. Other DD&A expense of $169,650 for the three-month period ended June 30,
2000 was slightly higher than the prior year total of $167,602 in the same
period of 1999. Year-to-date, other DD&A decreased six-percent from $361,988
in 1999 to $339,219 for the comparable six-month period ended June 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 second quarter of 2000
decreased 8% from $1.1 million to $1.0 million, as compared to the three months
ended June 30, 1999. The decrease in G&A was primarily attributable to lower
salaries and related benefits attributable to a work force reduction during
January 2000. G&A expense for the six-month period ended June 30, 2000 totaled
$1.9 million, a decrease of 10% from the $2.1 million incurred during the six
months ended June 30, 1999. For the second quarter of 2000 and 1999, overhead
reimbursement fees recorded as a reduction to G&A totaled approximately $29,600
and $132,200, respectively. For the six months ended June 30, 2000 and 1999,
overhead reimbursement fees reduced G&A by approximately $63,000 and $187,000,
respectively. G&A on a unit of production basis for the three-month periods
ended June 30, 2000 and 1999 was $0.63 per Mcfe and $0.54 per Mcfe,
respectively. For the year-to-date periods ended June 30, 2000 and 1999, G&A on
a unit of production basis was $0.63 per Mcfe and $0.54 per Mcfe, respectively.
Unearned compensation expense for the three months ended June 30, 2000
decreased from $83,977 to $8,589, as compared to the three months ended June 30,
1999. For the six months ended June 30, 2000, unearned compensation expense
totaled $17,178 compared to $167,953 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 three-month and six-month periods ending
June 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 $46,599
for the second quarter of 2000 compared to $29,860 in the second quarter of
1999. Gross interest expense was $150,526 for the second quarter of 2000 on
weighted average debt of approximately $6.1 million compared to gross interest
expense of $150,545 on weighted average debt of approximately $9.1 million for
the same prior year period. Capitalized interest in the second quarter of 2000
totaled $103,927 compared to $120,685 in the second quarter of 1999. For the
year-to-date period ended June 30, 2000, interest expense totaled $90,678, an
increase of 33% over the prior year period total of $68,186. Weighted average
debt was approximately $6.7 million for the six months ended June 30, 2000,
resulting in gross interest costs of $325,607. For the same period in 1999,
weighted average debt of $10.5 million resulted in gross interest costs of
$414,468. Capitalized interest for the six months ended June 30, 2000 totaled
$234,929, a decrease of 32% over the prior year amount of $346,282 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 six-month periods ended June 30,
2000 compared to the same periods in the prior year.
Interest income totaled $13,637 for the three months ended June 30, 2000
and $26,870 for the 2000 year-to-date period compared to $14,689 and $25,711 in
the respective prior year periods. The increase in interest income is due to the
overall increase in invested overnight money market funds.
Due to our significant deferred tax assets, no tax expense (benefit) was
recorded for the three-month or six-month periods ended June 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 second quarter of 2000, we reported net income of $208,591, or
$0.02 per share, compared to a net loss of $(239,953), or $(0.03) per share, for
the same period in 1999. For the six months ended June 30, 2000, we reported net
income of $567,862, or $0.06 per share, compared to a net loss of $(545,441), or
$(0.07) per share, in the comparable 1999 period. Weighted average shares
outstanding increased from approximately 8.2 million for the six months ended
June 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.
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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.
We are currently in negotiations for a credit facility with a new bank. The new
facility is expected to have an increased borrowing base with monthly commitment
reductions that are lower than our current facility requirements and are
deferred until October 1, 2000. Although we believe this new facility will be
available to us in the near future, there can be no assurance that we will enter
into this credit facility or that its terms will be as currently expected. 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.
LIQUIDITY
We had cash and cash equivalents at June 30, 2000 of $1.1 million
consisting primarily of short-term money market investments, as compared to
$577,864 at December 31, 1999. Our working capital deficit was $(353,188) at
June 30, 2000, as compared to $(4,977,421) at December 31, 1999 and our ratio of
current assets to current liabilities was 0.96:1 at June 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 $3,696,812 at June 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 1.87:1 at June 30, 2000 compared to 0.86:1 at December 31, 1999. The
reduction in our working capital deficit and increased current ratio at June 30,
2000 resulted from an increase in current assets related to $2.0 million in
proceeds due in July from the sale of our investment in Frontera as well as a
decrease in accrued liabilities that resulted from settlement with industry
partners of revenues held in suspense.
CASH FLOWS
Cash flows provided by operations were $2.8 million and $2.1 million for
the six months ended June 30, 2000 and 1999, respectively. The increase in cash
flows provided by operations for the six months ended June 30, 2000 is primarily
due to net income in the current year as compared to a net loss in the prior
year and a decrease in accrued liabilities for the six months ended June 30,
2000 as compared to the prior year period. During the second quarter of 2000, we
settled disputed amounts with an industry partner and released certain amounts
held in suspense. Operating cash flows, before changes in working capital, were
$4.9 million and $3.9 million for the six months ended June 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 $135,528 for the six months
ended June 30, 2000 compared to $3.96 million used in the same period of 1999.
During the six months ended June 30, 2000, we continued to reinvest a
substantial portion of our cash flows to increase our 3-D project portfolio,
improve our 3-D seismic interpretation technology and fund our drilling program.
Capital expenditures during the six months ended June 30, 2000 were
approximately $3.5 million as compared to $5.5 million during the same period in
1999. We expended $2.0 million in our drilling operations resulting in the
drilling of 7 gross (1.84 net) wells during the six months ended June 30, 2000
as compared to 8 gross (3.19 net) wells during the same period in 1999. We
currently have three gross wells drilling. The remaining cost capitalized to oil
and natural gas properties was capitalized internal G&G and interest of
approximately $1.0 million. Total capital expenditures for 2000 are expected to
be approximately $9.4 million. Other investing activity also included proceeds
from the sale of oil and natural gas properties of approximately $1.8 million
for the six months ended June 30, 2000 and proceeds from the sale of our
investment in Frontera of $1.6 million received as of June 30, 2000. For the six
months ended June 30, 1999, we had proceeds from the sale of oil and natural gas
properties of $1.6 million offset by expenditures on our investment in Frontera
of $122,297.
Cash used in financing activities totaled $2.15 million for the six months
ended June 30, 2000 and included borrowings under our credit facility of
$850,000 and repayments of $3.0 million. For the six months ended June 30, 1999,
cash provided by financing activities totaled $2.0 million and included net
borrowings of $5.35 million. In addition, we received proceeds from a private
offering totaling $7.4 million, net of offering costs, in May of 1999.
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REVOLVING CREDIT FACILITY
We are a party to a credit facility (the "Revolving Credit Facility") with
a bank. Borrowings under the Revolving Credit Facility are limited by a
borrowing base, as defined in the Revolving Credit Facility, and bear 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 is secured by
substantially all of our assets.
Each quarter, at our election or at the election of the bank, the
borrowing base under the Revolving Credit Facility can be redetermined. The
borrowing base is also subject to mandatory reductions, which are subject to
revision each time the borrowing base is redetermined. The borrowing base is
currently required to be reduced on the first day of each month by $450,000. In
April 2000, we sold certain oil and natural gas properties (see Note 5), that
caused an additional reduction in our borrowing base. At June 30, 2000, the
borrowings under this facility totaled $4.65 million with no remaining borrowing
base available for future borrowings. For the six months ended June 30, 2000,
the weighted average debt outstanding was $6.7 million and the weighted-average
interest rate was 9.71%.
The Revolving 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 Revolving Credit
Facility also contains certain financial covenants. The Tangible Net Worth
Covenant requires 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 requires 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 must be at least
1.25 to 1.00. At June 30, 2000 and December 31, 1999 we were in compliance with
the above mentioned covenants.
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. We are in the process of analyzing the
impact of adoption on our financial statements, as well as any additional
disclosure requirements.
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.
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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, our expected new credit facility (including
anticipated amounts available for borrowing), 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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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 June 30, 2000 floating interest rate of 9.5%, 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 six months ended June 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 $21,000. During the
six months ended June 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. A 10% change in the natural
gas price per MMbtu would cause the total market value of the natural gas
collars to increase or decrease by approximately $144,000. At June 30, 2000, the
market value of the outstanding hedges were approximately $(1.1) million.
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PART II - OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS
The Company, as one of three plaintiffs, has filed a lawsuit against
BNP Petroleum Corporation, 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 between plaintiffs and defendants whereby the defendants were
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 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, bad-faith litigation, and
exemplary damages. The case proceeded to trial before the Court (without a jury)
on June 19, 2000. The trial is currently in recess and is scheduled to resume on
September 5, 2000. On July 3, 2000, the Company became aware that on June 30,
2000, defendants filed a second amended answer and counterclaim and certain
supplemental responses to requests 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.
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. An adverse outcome on the
counterclaims or related matters could have a material adverse effect on the
Company.
The Company has 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. This breach of contract allegation is the subject of an additional
lawsuit by plaintiffs in the 165th District Court in Harris County, Texas. The
Company is seeking damages as a result of defendants' actions as well as costs
and attorneys' fees.
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
(A) Annual Meeting of Shareholders on May 3, 2000.
(B) Set fourth below are the results of the voting with respect to each matter
acted upon:
<TABLE>
<CAPTION>
Broker
For Against Withheld Abstain Non Votes
--- ------- -------- ------- ---------
<S> <C> <C> <C> <C> <C>
Election of Directors:
John W. Elias 6,640,180 125,479
John Sfondrini 5,762,401 1,003,258
Approval of the Appointment of
Deloitte and Touche LLP as
independent Public Accountants 6,745,826 4,318 15,515
</TABLE>
In addition to the election of the directors indicated above, the terms of
the following directors continued as directors following the meeting: Stanley
S. Raphael, Robert W. Shower, Vincent S. Andrews, David B. Benedict and Nils
P. Peterson.
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<PAGE>
ITEM 5 - OTHER INFORMATION....................................... None
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(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)).
+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).
- 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.
+4.5 - 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).
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<PAGE>
+4.6 - 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).
+4.7 - 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)).
+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).
-20-
<PAGE>
+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>
+ Incorporated by reference as indicated.
(B) Reports on Form 8-K................................... None
-21-
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf 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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