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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, 2002
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 9, 2002
----- -----------------------------
Common Stock 9,400,946
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------
June 30, December 31,
2002 2001
----------- -----------
(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 704,849 $ 793,287
Accounts receivable, trade, net of allowance of
$525,248 at June 30, 2002 and December 31, 2001,
respectively 6,276,020 5,184,522
Accounts receivable, joint interest owners, net of
allowance of $163,000 at each of June 30, 2002 and
December 31, 2001 994,747 322,001
Current deferred tax asset 584,580 584,580
Other current assets 878,401 402,566
----------- -----------
Total current assets 9,438,597 7,286,956
PROPERTY AND EQUIPMENT, Net - full cost method of
accounting for oil and natural gas properties 69,884,732 66,853,094
DEFERRED TAX ASSET 246,212 556,317
OTHER ASSETS 7,788 7,788
----------- -----------
TOTAL ASSETS $79,577,329 $74,704,155
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 1,757,165 $ 1,412,451
Accrued liabilities 2,827,548 5,192,440
Accrued interest payable 58,299 --
----------- -----------
Total current liabilities 4,643,012 6,604,891
LONG-TERM DEBT 16,000,000 10,000,000
----------- -----------
Total liabilities 20,643,012 16,604,891
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 8)
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; 9,399,446 shares and 9,305,079 shares
issued and outstanding at June 30, 2002 and December
31, 2001, respectively 93,996 93,051
Additional paid-in capital 56,416,482 56,139,451
Retained earnings 2,423,839 1,866,762
----------- -----------
Total stockholders' equity 58,934,317 58,099,264
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $79,577,329 $74,704,155
=========== ===========
See accompanying notes to consolidated financial statements.
2
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
- -------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------- ------------------------------
2002 2001 2002 2001
----------- ----------- ------------ ------------
OIL AND NATURAL GAS REVENUE $ 6,432,149 $ 8,045,144 $ 11,339,746 $ 19,568,215
OPERATING EXPENSES:
Lifting costs 600,564 695,416 1,196,809 1,303,326
Severance and ad valorem taxes 450,241 629,407 885,963 1,543,734
Depletion, depreciation and
amortization 2,694,566 2,464,897 5,526,729 4,463,556
General and administrative
expenses 1,367,793 1,410,128 2,609,211 2,638,469
Deferred compensation expense 105,432 10,409 210,310 (698,748)
----------- ----------- ------------ ------------
Total operating expenses 5,218,596 5,210,257 10,429,022 9,250,337
----------- ----------- ------------ ------------
OPERATING INCOME 1,213,553 2,834,887 910,724 10,317,878
OTHER INCOME AND EXPENSE:
Interest income 3,267 55,928 7,145 78,829
Interest expense, net (25,343) (74,899) (50,687) (108,604)
----------- ----------- ------------ ------------
INCOME BEFORE INCOME TAXES 1,191,477 2,815,916 867,182 10,288,103
INCOME TAX BENEFIT (EXPENSE) (427,492) 240,076 (310,105) (781,595)
----------- ----------- ------------ ------------
NET INCOME 763,985 3,055,992 557,077 9,506,508
OTHER COMPREHENSIVE INCOME:
Transition adjustment -- -- -- (1,137,221)
Realization of hedging losses -- 49,542 -- 924,332
Change in valuation of hedging
instruments 70,539 -- -- 200,101
----------- ----------- ------------ ------------
COMPREHENSIVE INCOME $ 834,524 $ 3,105,534 $ 557,077 $ 9,493,720
=========== =========== ============ ============
BASIC EARNINGS PER SHARE $ 0.08 $ 0.33 $ 0.06 $ 1.03
=========== =========== ============ ============
DILUTED EARNINGS PER SHARE $ 0.08 $ 0.31 $ 0.06 $ 0.97
=========== =========== ============ ============
BASIC WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 9,391,267 9,289,027 9,358,253 9,256,680
=========== =========== ============ ============
DILUTED WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 9,695,245 9,867,502 9,647,045 9,834,664
=========== =========== ============ ============
See accompanying notes to consolidated financial statements.
3
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
- -----------------------------------------------------------------------------------------
Six Months Ended June 30,
-----------------------------
2002 2001
----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 557,077 $ 9,506,508
Adjustments to reconcile net income to net cash provided
by operating activities:
Deferred income taxes 310,105 781,595
Depletion, depreciation and amortization 5,526,729 4,463,556
Bad debt expense -- 300,000
Amortization of deferred loan costs 50,687 50,710
Deferred loss from derivative activity -- (12,788)
Deferred compensation 210,310 (698,748)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, trade (1,091,498) 3,962,903
Increase in accounts receivable, joint interest owners (672,746) (19,160)
Increase in other current assets (526,522) (828,036)
Increase (decrease) in accounts payable, trade 344,714 (698,457)
Increase (decrease) in accrued liabilities (2,364,892) 204,364
Increase (decrease) in accrued interest payable 58,299 (50,385)
----------- ------------
Net cash provided by operating activities 2,402,263 16,962,062
----------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment additions (8,558,367) (8,236,469)
----------- ------------
Net cash used in investing activities (8,558,367) (8,236,469)
----------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from long-term debt 6,500,000 1,000,000
Payments of long-term debt (500,000) (4,000,000)
Net proceeds from issuance of common stock 67,666 390,801
Other -- (7,669)
----------- ------------
Net cash provided by (used in) financing activities 6,067,666 (2,616,868)
----------- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (88,438) 6,108,725
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 793,287 247,981
----------- ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 704,849 $ 6,356,706
=========== ============
See accompanying notes to consolidated financial statements.
4
EDGE PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
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 accounting principles generally accepted in the
United States of America 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, 2001.
Our accounting policies are consistent with those discussed in our Form
10-K, except as discussed below. You should refer to our Form 10-K for a further
discussion of those policies.
Revenue adjustment to actual - Second quarter and year-to-date results for
the periods ended June 30, 2002 were favorably impacted by the current
recognition of revenue associated with certain underaccruals dating back to
1994. During the second quarter of 2002, we completed a yearlong project, that
reconciled amounts received for production from two of our older producing
properties to amounts accrued in prior periods. After reaching a final
determination of ownership interest, it was determined that over 142,000
thousand cubic feet of gas equivalent (Mcfe) had been underaccrued over the
period from fourth quarter 1994 to present. This resulted in additional revenue
of approximately $577,200 reported in the second quarter of 2002. After
adjusting for severance taxes, depletion and income taxes, this had the effect
of increasing net income for both the quarter and year-to-date periods of 2002
by approximately $212,300, or $0.02 basic earnings per share.
Reclassifications - Certain prior year balances have been reclassified to
conform to current year presentation.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS - In August 2001, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations. This
Statement requires companies to record a liability relating to the retirement
and removal of assets used in their business. The liability is discounted to its
present value, and the related asset value is increased by the amount of the
resulting liability. Over the life of the asset, the liability will be accreted
to its future value and eventually extinguished when the asset is taken out of
service. The provisions of this Statement are effective for fiscal years
beginning after June 15, 2002. We are currently evaluating the effects of this
pronouncement.
ACCOUNTING FOR THE IMPAIRMENT OR DISPOSAL OF LONG-LIVED ASSETS - In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. This Statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
cost to sell. The standard also expanded the scope of discontinued operations to
include all components of an entity with operations of the entity in a disposal
transaction. We adopted the provisions of this statement effective January 1,
2002 and it had no impact on our financial statements.
ACCOUNTING FOR GAINS AND LOSSES FROM EXTINGUISHMENT OF DEBT - In April 2002,
the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections. This Statement
rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt,
which required all gains and losses from extinguishment of debt to be aggregated
and, if material, classified as an extraordinary item, net of related income
taxes. As a result, the criteria in Accounting Principles Board Opinion
5
(APB) 30 will now be used to classify those gains and losses. Any gain or loss
on extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. We are currently
evaluating the effects of this pronouncement.
ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES - In July
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. This Statement requires the recognition of costs associated
with exit or disposal activities when they are incurred rather than at the date
of a commitment to an exit or disposal plan. The provisions of this Statement
are effective for exit or disposal activities initiated after December 31, 2002.
We are currently evaluating the effects of this pronouncement.
2. LONG TERM DEBT
During the first half of 2002, we borrowed $6.5 million and repaid $500,000
under our credit facility (the "Credit Facility"). As of June 30, 2002, $16.0
million was outstanding under our credit facility. Borrowings under the Credit
Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.5%.
In August 2002, the borrowing base was increased to $25 million and the maturity
date extended to October 6, 2004. The Credit Facility is secured by
substantially all of our assets.
We expect the next borrowing base redetermination to be during the first quarter
of 2003. The borrowing base is not subject to automatic reductions.
The 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, and engaging in
merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in
the agreement, for the four fiscal quarters then ended to (b) our consolidated
interest expense for the four fiscal quarters then ended, to not be less than
3.5 to 1.0. The Working Capital ratio requires that the amount of our
consolidated current assets less our consolidated liabilities, as defined in the
agreement, be at least $1.0 million. The Allowable Expenses ratio requires that
(a) the aggregate amount of our 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) our year-to-date consolidated oil and gas
revenue, net of hedging activity, for the period from January 1 of such year
through the fiscal quarter then ended, to be less than .40 to 1.0. At June 30,
2002, we were in compliance with the above-mentioned covenants.
3. EARNINGS PER SHARE
We account for earnings per share in accordance with SFAS No. 128, Earnings
per Share, 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.
6
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.
Three Months Ended June 30, 2002 Three Months Ended June 30, 2001
---------------------------------------- -----------------------------------------
Income Shares Per Share Income Shares Per Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- ------ ----------- ------------- ------
BASIC EPS
Income available to
common stockholders $763,985 9,391,267 $0.08 $3,055,992 9,289,027 $0.33
Effect of Dilutive
Securities:
Restricted stock -- 123,518 -- -- 195,384 (0.01)
Common stock options -- 151,882 -- -- 252,680 (0.01)
Warrants -- 28,578 -- -- 130,411 --
-------- --------- ----- ---------- --------- -----
DILUTED EPS
Income available to
common stockholders $763,985 9,695,245 $0.08 $3,055,992 9,867,502 $0.31
======== ========= ===== ========== ========= =====
Six Months Ended June 30, 2002 Six Months Ended June 30, 2001
---------------------------------------- -----------------------------------------
Income Shares Per Share Income Shares Per Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- ------ ----------- ------------- ------
BASIC EPS
Income available to
common stockholders $557,077 9,358,253 $0.06 $9,506,508 9,256,680 $1.03
Effect of Dilutive
Securities:
Restricted stock -- 151,062 -- -- 163,654 (0.02)
Common stock options -- 130,455 -- -- 273,265 (0.03)
Warrants -- 7,275 -- -- 141,065 (0.01)
-------- --------- ----- ---------- --------- -----
DILUTED EPS
Income available to
common stockholders $557,077 9,647,045 $0.06 $9,506,508 9,834,664 $0.97
======== ========= ===== ========== ========= =====
4. INCOME TAXES
We account for income taxes under the provisions of SFAS No. 109,
Accounting for Income Taxes, which provides for an asset and liability approach
in accounting for income taxes. Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax consequences, using
currently enacted tax laws, attributable to temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and
the amounts calculated for income tax purposes.
During 2001, we determined that it was more likely than not that future
taxable income would be sufficient to realize our recorded tax assets and
accordingly, a valuation allowance totaling $3.2 million was reversed. We
currently estimate that our effective tax rate for the year ending December 31,
2002 will be approximately 36%. For the three months ended June 30, 2002, a
provision for income taxes of $427,492 was reported. In the comparable prior
year period we reported an income tax benefit of $240,076. For the six months
ended June 30, 2002 and 2001, we reported income tax expense of $310,105 and
$781,595, respectively.
7
5. EQUITY
We account for Stock Based Compensation in accordance with SFAS No. 123,
Accounting for Stock Based Compensation. 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 APB 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. At the effective date of SFAS No. 123, we
elected to continue to follow APB No. 25.
Deferred compensation cost reported in accordance with FASB Interpretation
No. (FIN) 44, Accounting for Certain Transactions Involving Stock Compensation,
was a credit of $303 for the six months ended June 30, 2002 compared to a credit
of $850,725 in the comparable prior year period. FIN 44 requires, among other
things, a non-cash charge to compensation expense if the price of our common
stock on the last trading day of a reporting period is greater that the exercise
price of certain options. FIN 44 could also result in a credit to compensation
expense to the extent that the trading price declines from the trading price as
of the end of the prior period, but not below the exercise price of the options.
We adjust deferred compensation expense upward or downward on a monthly basis,
to report under this rule as a result of non-qualified stock options granted to
employees and directors in prior years and re-priced in May of 1999, as well as
certain options newly issued in conjunction with the repricing as discussed
above.
During the first quarter of 2001, we purchased options exercisable for
133,645 shares of common stock from a former employee at a cost of $100,000, all
of which represents compensation expense.
6. 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 six months ended June 30, 2002 and
2001 is presented below:
We issued 45,336 shares of common stock to employees during the first
quarter of 2002 with a fair market value of $174,575 at the time of grant. These
shares represent one-third of the shares subject to restricted stock grants made
effective in January 2001 and March 2000.
We issued 29,400 shares of common stock to employees during the second
quarter of 2002 with a fair market value of $227,850 at the time of grant. These
shares represent one-third of the shares subject to a restricted stock grant
made effective in April 2001.
We issued 3,831 shares of common stock during the second quarter of 2002
with a fair market value of $20,266. These shares represent Edge's matching
contribution under the Company's 401(k) plan.
We issued 42,103 shares of common stock to employees during the first
quarter of 2001 with a fair market value of $126,300 at the time of grant. These
shares represent one-third of the shares subject to a restricted stock grant
made effective March 2000.
Supplemental Disclosure of Cash Flow Information
For the Six Months
Ended June 30,
---------------------------
2002 2001
---------- --------
Cash paid during the period for:
Interest, net of amounts capitalized $ -- $ 11,986
Estimated alternative minimum tax
payments -- 322,000
Interest paid for the six months ended June 30, 2002 and 2001 excludes
amounts capitalized of $348,467 and $24,402, respectively.
8
7. 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, collars and
floors) for a portion of our oil and natural gas production to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements may limit the benefit to us of increases in
the price of oil and natural gas, it may also limit the downside risk of adverse
price movements. Our hedging arrangements, to the extent we enter into any,
apply to only a portion of our production and provide only partial price
protection against declines in oil and natural gas prices and limit 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 revenue during the period the hedged production occurs.
The following was the impact on oil and natural gas revenue from hedging
activities for the six months ended June 30, 2002 and 2001:
Loss
-------------------------------------
Six Months Ended
MMBtu June 30,
Effective Dates Price Per Volumes -------------------------------------
Hedge Type Beg. Ending MMBtu Per Day 2002 2001
- ---------------------- --------- ----------- ---------------- ------------ ---------------- ----------------
Natural Gas Floor 4/1/02 6/30/02 $2.65 18,000 $ (163,800) $ --
Natural Gas Collar 1/1/01 1/31/01 $4.50 - $6.70 4,000 -- (389,360)
Amortization of loss from close out of hedge -- (534,972)
------------ -----------
Total $ (163,800) $ (924,332)
============ ===========
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 revenue for the six-month period ended
June 30, 2002 was $(163,800) representing net losses from hedging activity. In
March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65 per MMbtu for
the period April 1, 2002 through June 30, 2002, at a cost of $163,800. No hedges
were in place for future production at June 30, 2002.
Included within oil and natural gas revenue for the six months ended June
30, 2001 was $(924,332) representing net losses from hedging activity. During
December 2000, we entered into a natural gas collar covering 4,000 MMbtu per day
for the period January 1, 2001 to December 31, 2001 with a floor of $4.50 per
MMBtu and a ceiling of $6.70 per MMbtu. For the month of January 2001 we
realized a loss on hedging activity of $(389,360). On January 3, 2001, we closed
out the hedge for the period February 1, 2001 to December 31, 2001 at a cost of
$547,760. In accordance with SFAS 133, this amount is amortized over the period
of the hedge based on the forward pricing curve at the time the hedge was closed
out. We recorded amortization of $(534,972) in oil and natural gas revenue for
the close out cost of the hedge during the first half of 2001 with the balance
of $12,788 amortized over the remainder of 2001.
8. COMMITMENTS AND CONTINGENCIES
From time to time we are a party to various legal proceedings arising in
the ordinary course of business. While the outcome of lawsuits cannot be
predicted with certainty, we are not currently a party to any proceeding that we
believe, if determined in a manner adverse to us, could have a potential
material adverse effect on our financial condition, results of operations or
cash flows except for the litigation described below. We do not believe that the
ultimate outcome of this litigation will have a material adverse effect on us.
In October 2001, the Company was sued by certain mineral owners seeking to
cancel a portion of our Mew lease, upon which the Company and its partners
drilled and completed the Mew No. 1 well in Duval County, Texas. The suit names
the Company, Santos USA and Mark Smith, an independent landman, as Defendants,
and is filed in the 229th Judicial District Court of Duval County, Texas. The
suit seeks a declaratory judgment to set aside certain quitclaim deeds between
the Mew lessors that were intended to result in a partition of
9
the mineral estate between the various members of the Mew family in the land
where the well is located and other lands. The pleadings allege failure of
consideration, fraud, failure to consummate the partition, bad faith trespass
and conversion. As part of the leasing effort for the prospect, some members of
the Mew family had sought to partition their minerals under the tracts where
they owned the surface in full. The Mew heirs, from whom the Company acquired
leases, could lose a portion of their mineral interest if the quitclaim deeds
are set aside. Were this to happen, it could have the effect of voiding the
Company's leases as to an undivided one-third of the unit acreage for the Mew
well and the Mew lease. Plaintiffs seek unspecified actual and exemplary damages
against the Company and Santos arising out of alleged fraud committed by the
Company and Mark Smith. They also seek damages from Santos for the value of the
oil and natural gas produced and saved from the Mew well, or alternatively, for
the value of the oil and natural gas produced less the cost of drilling,
completing and operating the well. The Company has a 12.5% working interest in
the well. As of June 30, 2002, the Mew well has produced $7.3 million in net
revenue and has cost $2.6 million to drill, complete and operate. Estimated
remaining gross proved reserves are 53.6 MBbls and 3.9 Bcf. The Company has
filed an answer in the case and intends to vigorously defend its position that
the Mew lease is valid and subsisting in its entirety. Santos has filed a plea
of abatement asking that the case be dismissed for failure to join necessary and
indispensable parties. Pursuant to Santos' motion, certain additional defendants
have been joined in the case. At this point, it is not possible to determine the
ultimate outcome of this litigation or the exposure, if any, the Company may
have.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of litigation, the Company believes
there is no question that it acted in good faith and intends to vigorously
defend its position. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. Due to the uncertainty of the
final outcome, the Company has ceased to record revenue from the properties as
of August 1, 2001, which net to the Company averaged approximately 1.4 Mmcfe/d
of production at the time the well was shut-in. In addition, the Company removed
associated reserves of 1.4 Bcfe from its total proved reserves. The Company
believes this potential loss is not material to its financial condition or
results of operations.
10
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, 2001.
OVERVIEW
The following matters had a significant impact on our results of operations
and financial position for the six months ended June 30, 2002:
Revenue adjustment to actual - Second quarter and year-to-date results for
the periods ended June 30, 2002 were favorably impacted by the current
recognition of revenue associated with certain underaccruals dating back to
1994. During the second quarter of 2002, we completed a yearlong project that
reconciled amounts received for production from two of our older producing
properties to amounts accrued in prior periods. After reaching a final
determination of ownership interest, it was determined that over 142,000
thousand cubic feet of gas equivalent (Mcfe) had been underaccrued over the
period from fourth quarter 1994 to present. This resulted in additional revenue
of approximately $577,200 reported in the second quarter of 2002. After
adjusting for severance taxes, depletion and income taxes, this had the effect
of increasing net income for both the quarter and year-to-date periods of 2002
by approximately $212,300, or $0.02 basic earnings per share.
Commodity Prices - The average realized price for our production, before the
impact of the revenue adjustments, decreased 48% from $5.44 per Mcfe for the six
months ended June 30, 2001 to $2.84 per Mcfe for the comparable period this
year. These average prices included the impact of hedging losses which lowered
the realized price by $0.26 per Mcfe and $0.04 per Mcfe for the six months ended
June 30, 2001 and 2002, respectively.
Debt - As of June 30, 2002, borrowings outstanding under our Credit
Facility totaled $16 million compared to borrowings of $10.0 million at December
31, 2001. Proceeds from borrowings under the Credit Facility were used to fund
the December 2001 property acquisition, the cash payment of $2.5 million to BNP
for settlement of litigation, the 2002 acquisition of additional interest in
Gato Creek and first half 2002 capital expenditures. In August 2002, our
borrowing base was increased from $19 million to $25 million. In addition, the
maturity date was extended to October 6, 2003 with no automatic monthly
borrowing base reductions. We expect the next borrowing base redetermination to
be during first quarter of 2003.
RESULTS OF OPERATIONS
REVENUE AND PRODUCTION
Oil and natural gas revenue reported for the second quarter of 2002 totaled
$6.4 million. Excluding the $577,200 adjustment discussed above, revenue for the
second quarter totaled $5.9 million, a decrease of 27% compared to the same
period in 2001 due to both lower average realized prices and production declines
compared to the prior year period. Natural gas production comprised 76% of total
production on an equivalent Mcf basis and contributed 76% of total revenue for
the second quarter of 2002. Oil and condensate production was 13% of total
production and contributed 17% of total oil and gas revenue while natural gas
liquids (NGLs) production comprised 11% of total production and contributed 7%
of total oil and gas revenue. In the comparable 2001 period, natural gas
production comprised 88% of total production and contributed 89% of total
revenue. Oil and condensate production was 10% of total production and 10% of
revenue and NGLs production comprised 2% of total production and contributed 1%
of total revenue.
11
Oil and natural gas revenue reported for the six months ended June 30, 2002
totaled $11.3 million. Excluding the underaccrual adjustment, revenue for the
six-month period totaled $10.8 million, a decrease of 45% over the same period
in 2001. While production on a Mcfe basis, excluding the underaccrual
adjustment of 142,000 Mcfe, increased 5% over the prior year period, the impact
of lower average realized prices more than offset the favorable production
increase. Natural gas production comprised 80% of total production and
contributed 81% of total revenue for the year-to-date period. Oil and condensate
production was 11% of total production and contributed 14% of total oil and gas
revenue while NGL production comprised 9% of total production and contributed 5%
of total oil and gas revenue. In the comparable 2001 period, natural gas
production comprised 90% of total production and contributed 92% of total
revenue. Oil and condensate production was 9% of total production and 7% of
revenue and NGLs production comprised 1% of total production and contributed 1%
of total revenue.
The following table summarizes volume and price information with respect to
our oil and gas production for the quarter and year-to-date periods ended June
30, 2002, and 2001. Amounts shown in the table and in the revenue comparisons
discussed below exclude the 2002 underaccrual adjustment of 142,000 Mcfe or
$577,200.
For the Three Months For the Six Months
Ended June 30, Ended June 30,
------------------------------------------ -----------------------------------------
Increase Increase
2002 2001 (Decrease) 2002 2001 (Decrease)
---- ---- ---------- ---- ---- ----------
Gas Volume - MCFGPD (1) 14,720 17,697 (2,977) 16,812 17,826 (1,014)
Average Gas Price - per MCF $3.32 $4.45 $(1.13) $2.85 $5.57 $(2.72)
Oil and Condensate Volume - BPD (2) 412 333 79 367 293 74
Average Oil Price - per barrel $26.89 $25.90 $0.99 $22.76 $27.10 $(4.34)
Natural Gas Liquids Volume - BPD (2) 371 63 308 325 49 276
Average NGL Price - per barrel $11.93 $16.27 $(4.34) $10.04 $18.12 $(8.08)
- ------------------------------------------
(1) MCFGPD - thousand cubic feet of gas per day
(2) BPD - barrels per day
SECOND QUARTER 2002 COMPARED TO THE SECOND QUARTER 2001
Natural gas sales revenue, excluding the underaccrual adjustment, decreased
38%, from $7.2 million for the second quarter of 2001 to $4.4 million for the
same period in 2002 due to the impact of lower average natural gas prices and
declines in production. The average realized price for natural gas production,
including the effect of hedging activity, was $3.32 per Mcf for the second
quarter of 2002, a decrease of 25% over the 2001-second quarter average price of
$4.45 per Mcf. This decrease in average prices decreased revenue by
approximately $1.5 million (based on current quarter production). Production
volumes for natural gas for the three months ended June 30, 2002 decreased 17%
from 17,697 MCFGPD for the second quarter of 2001 to 14,720 MCFGPD for the
comparable period in 2002, due primarily to production declines at our Mire #1
well in Louisiana during the quarter as well as an overall decline in production
at our Austin and O'Connor Ranch properties and the loss of North La Copita
production. This decrease in natural gas production during the second quarter of
2002 decreased revenue by $1.2 million (based on 2001 second quarter average
prices).
Revenue from sales of oil and condensate, excluding the underaccrual
adjustment, increased 28% from $784,992 in the second quarter of 2001 to
$1,007,345 for the comparable 2002 period due to higher average realized prices
and increased production. The average realized price for oil and condensate in
the second quarter of 2002 was $26.89 per barrel compared to $25.90 per barrel
for the same period in 2001. This increase in the average realized price
received for our oil and condensate increased revenue $37,400 (based on current
quarter production). Production volumes for
12
oil and condensate increased 24% from 333 BPD in the second quarter of 2001 to
412 BPD for the comparable period in 2002. This increase in production favorably
impacted quarterly revenue by $184,900 (based on 2001 second quarter average
prices).
Revenue from sales of natural gas liquids (NGLs), excluding the underaccrual
adjustment, increased significantly from $93,281 in the second quarter of 2001
to $403,045 for the comparable 2002 period due to higher production, offset in
part by the effect of lower prices. Production volumes for NGLs increased 489%
from 63 BPD in the second quarter of 2001 to 371 BPD for the comparable period
in 2002. Due to high natural gas prices, we elected not to process much of our
gas during the first half of 2001. This increase in production favorably
impacted quarterly revenue by $456,200 (based on 2001 second quarter average
prices). The average realized price for NGLs in the second quarter of 2002 was
$11.93 per barrel compared to $16.27 per barrel for the same period in 2001.
This decrease in the average realized price received for our NGLs decreased
revenue $146,400 (based on current quarter production).
SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO THE SIX MONTHS ENDED JUNE 30, 2001
Natural gas sales revenue, excluding the underaccrual adjustment, decreased
52%, from $18.0 million for the six months ended June 30, 2001 to $8.7 million
for the same period in 2002, due primarily to lower average natural gas prices
and a decrease in production, partially offset by a greater negative impact of
hedging activities in the prior year period. The average realized price for
natural gas production, including the effect of hedging activity, was $2.85 per
Mcf for the 2002 year-to-date period, a decrease of 49% over the average price
for the six months of 2001 of $5.57 per Mcf. This decrease in average prices
decreased revenue by approximately $8.3 million (based on current year-to-date
production). Included within natural gas revenue for the six months ended June
30, 2002 and 2001 was $(163,800) and $(924,332), respectively, representing
losses from hedging activities. Production volumes for natural gas for the six
months ended June 30, 2002 decreased 6% from 17,826 MCFGPD for 2001 to 16,812
MCFGPD for the comparable period in 2002. This decrease in natural gas
production during the six months ended June 30, 2002 decreased revenue by $1.0
million (based on 2001 year-to-date average prices).
Revenue from sales of oil and condensate, excluding the underaccrual
adjustment, increased 5% from $1.4 million in 2001 to $1.5 million for the
comparable 2002 period due primarily to higher average oil production in 2002,
partially offset by lower average realized prices. Production volumes for oil
and condensate increased 25% from 293 BPD for the six months ended June 30, 2001
to 367 BPD for the comparable period in 2002. This increase in production
favorably impacted year-to-date revenue by $363,300 (based on 2001 year-to-date
average prices). The average realized price for oil and condensate for the six
months ended June 30, 2002 was $22.76 per barrel, compared to $27.10 per barrel
for the same period in 2001. This decrease in the average realized price
received for our oil and condensate decreased revenue $288,300 (based on current
year-to-date production).
Revenue from sales of natural gas liquids (NGLs), excluding the underaccrual
adjustment, increased significantly from $162,158 for the six months ended June
30, 2001 to $590,765 for the comparable 2002 period due to higher production,
partially offset by lower average realized prices. Production volumes for NGLs
increased 563% from 49 BPD in the six-month period of 2001 to 325 BPD for the
comparable period in 2002. Due to high natural gas prices, we elected not to
process much of our gas during 2001. This increase in production favorably
impacted year-to-date revenue $903,700 (based on 2001 year-to-date average
prices). The average realized price for NGLs in the six months of 2002 was
$10.04 per barrel compared to $18.12 per barrel for the same period in 2001.
This decrease in the average realized price received for our NGLs decreased
revenue by $475,100 (based on current year-to-date production).
COSTS AND OPERATING EXPENSES
Lifting costs for the three-month period ended June 30, 2002 totaled
$600,564, a 14% decrease compared to the same period in 2001. On an equivalent
Mcf basis, lifting costs averaged $0.31 per Mcfe ($0.32 per Mcfe excluding the
underaccrual adjustment) for the three-month period ended June 30, 2002 compared
to $0.38 per Mcfe in the prior year period. For the six-month period ended June
30, 2001, lifting costs totaled $1.2 million, an 8% decrease compared to the
same period in 2001. Lifting costs were $0.30 per Mcfe (0.32 per Mcfe excluding
the underaccrual adjustment) for
13
the six-month period ended June 30, 2002 compared to $0.36 per Mcfe in the prior
year period. The decrease in costs was due primarily to high saltwater disposal
and natural gas processing costs recorded in 2001.
Severance and ad valorem taxes for the three months ended June 30, 2002
totaled $450,241. Excluding costs associated with the underaccrual, severance
and ad valorem taxes were $386,066 for the three months ended June 30, 2002, a
decrease of 39% from $629,407 in the comparable prior year period. Severance and
ad valorem taxes for the six months ended June 30, 2002 totaled $885,963.
Excluding costs associated with the underaccrual, severance and ad valorem taxes
totaled $821,788, a decrease of 47% from $1.5 million in the comparable prior
year period. The decrease in severance and ad valorem taxes in each of the 2002
periods was due primarily to higher severance taxes paid on the increased
revenue during the 2001 periods. Severance tax averaged 6.2% of revenue (6.4%
excluding the underaccrual adjustments) for the year-to-date 2002 period
compared to 7.1% for the same period in 2001.
Depletion, depreciation and amortization ("DD&A") expense for the
three-month and six-month periods ended June 30, 2002 totaled $2.7 million and
$5.5 million, respectively. Excluding costs associated with the underaccrual
adjustments, DD&A totaled $2.5 million and $5.3 million, respectively, for the
three months and six months ended June 30, 2002. This compares to $2.5 million
and $4.5 million in the same periods of 2001. Full cost DD&A on our oil and
natural gas properties totaled $2.5 million for the second quarter of 2002 ($2.4
million excluding the costs associated with the underaccrual adjustment)
compared to $2.3 million for the same period in 2001. Both the reported and the
adjusted depletion expense on a unit of production basis for the three-month
period ended June 30, 2002 were $1.33 per Mcfe compared to $1.26 per Mcfe in the
comparable prior year period. For the six months ended June 30, 2002 depletion
on our oil and natural gas properties totaled $5.2 million ($5.0 million
excluding the costs associated with the underaccrual adjustment) compared to
$4.1 million for the same period in 2001. Both the reported and the adjusted
depletion expense on a unit of production basis for the six-month period ended
June 30, 2002 were $1.32 per Mcfe compared to $1.15 per Mcfe for the six months
ended June 30, 2001. For the six months ended June 30, 2002 as compared to the
prior year period, a 15% increase in the overall depletion rate increased
depletion expense by $689,000 ($670,000 excluding the underaccrual adjustment)
while higher oil and natural gas production increased depletion expense by
$387,700 ($224,700 excluding the underaccrual adjustment). The increase in the
depletion rate was primarily due to a significantly higher amortizable base at
June 30, 2002 compared to June 30, 2001. Other DD&A expense totaled $160,233 and
$327,868 for the three-month and six-month periods ended June 30, 2002, slightly
lower than the comparable prior period totals of $169,536 and $341,179,
respectively.
General and administrative expenses ("G&A") for the second quarter of 2002
decreased 3% from the prior year period to $1.4 million. For the second quarter
of 2002 and 2001, overhead reimbursement fees recorded as a reduction to G&A
totaled $31,000 and $75,340, respectively. Capitalized G&A further reduced total
G&A by $370,400 and $411,000 for the three months ended June 30, 2002 and 2001,
respectively. For the six months ended June 30, 2002, G&A was $2.6 million, a
decrease of 1% compared to the prior year period. For the six months of 2002 and
2001, overhead reimbursement fees recorded as a reduction to G&A totaled $63,700
and $80,700, respectively. Capitalized G&A further reduced total G&A by $740,700
and $822,000 for the six months ended June 30, 2002 and 2001, respectively. The
decrease in G&A for both the three months and the six months ended June 30, 2002
was primarily attributable to bad debt expense reserved in 2001, partially
offset by higher salaries and benefits, higher professional services and higher
investor relation costs for 2002 compared to the same period in 2001. In
addition, compensation expense of $100,000 was recorded in the first quarter of
2001 related to the purchase of options from a former employee. G&A on a unit of
production basis for the six-month periods ended June 30, 2002 and 2001 was
$0.66 per Mcfe ($0.69 per Mcfe excluding the production associated with the
underaccrual adjustments) and $0.73 per Mcfe ($0.65 per Mcfe excluding the bad
debt expense), respectively.
Deferred compensation expense for the three-month and six-month periods
ended June 30, 2002 was a net credit of $(303), respectively. For the three
months and six months ended June 30, 2001, non-cash credits to deferred
compensation expense of $(95,353) and $(850,725), respectively, were recorded
related to FIN 44. Offsetting these credits was the amortization of compensation
expense related to restricted stock grants of $105,432 and $210,613 for the
three months and six months ended June 30, 2002, respectively, compared to
$105,762 and $151,977 for the same periods in 2001.
Other income and expense totaled $(22,076) and $(43,542) for the three-month
and six-month periods ended June 30, 2002, respectively, compared to expense of
$(18,971) and $(29,775) in the same prior year periods. Interest expense
incurred during the second quarter of 2002, all of which was capitalized,
totaled $128,868 on weighted
14
average debt of $14.3 million. For the six months ended June 30, 2002, interest
expense totaled $348,467, all of which was capitalized, on weighted average debt
of $12.7 million for the period. No borrowings under our credit facility were
outstanding during the second quarter of 2001 however we incurred $50,000 in
fees to maintain our available borrowing base. For the six months ended June 30,
2001, interest expense totaled $82,296, of which $24,402 was capitalized.
Weighted average debt was $737,000 for the six months ended June 30, 2001. Also
included in other income and expense was the amortization of deferred loan costs
that totaled $25,343 and $50,687 for the three-month and six-month periods ended
June 30, 2002, respectively, compared to amortization of $24,899 and $50,710 for
the same periods in 2001. Partially offsetting these expenses was interest
income for the three months and six months ended June 30, 2002 of $3,267 and
$7,145, respectively, compared to $55,928 and $78,829 for the same periods in
2001.
For the second quarter of 2002, we reported net income of $763,985 or $0.08
basic earnings per share. Excluding the underaccrual revenue adustment and
associated costs, net income was $551,697, or $0.06 basic earnings per share.
This compares to net income of $3.1 million, or $0.33 basic earnings per share,
for the same period in 2001. The second quarter of 2002 was not impacted by
non-cash deferred compensation expense related to repriced options (FIN 44). For
the second quarter of 2001, pro forma net income, excluding the non-cash
compensation credit related to FIN 44, was $2,967,883, or $0.32 per share.
For the six months ended June 30, 2002, we reported net income of $557,077
or $0.06 basic earnings per share. Excluding the underaccrual revenue adjustment
and associated costs, net income was $344,789, or $0.04 basic earnings per
share. This compares to net income of $9.5 million, or $1.03 basic earnings per
share, for the same period in 2001. Pro forma net income, excluding the non-cash
compensation credit related to FIN 44, was $556,883, or $0.06 per share for the
six months ended June 30, 2002 ($344,595, or $0.04 basic earnings per share
excluding the underaccrual adjustments) compared to $8.7 million, or $0.94 per
share for the same period in 2001. Weighted average shares outstanding increased
from approximately 9.3 million shares for the six months ended June 30, 2001 to
approximately 9.4 million shares in the comparable 2002 period. The increase was
due primarily to the exercise of stock options and the issuance of common stock
related to restricted stock grants.
LIQUIDITY AND CAPITAL RESOURCES
Due to our active exploration, development and acquisition activities, we
have experienced and expect to continue to experience substantial working
capital requirements. We intend to fund the remainder of our 2002 capital
expenditures, commitments and working capital requirements through cash flows
from operations, and to the extent necessary, other financing activities. We
expect that projected 2002 cash flows from operations, combined with modest
additional usage of our Credit Facility, will be sufficient to fund our budgeted
exploration and development program. We believe we will be able to generate
resources and liquidity sufficient to fund our capital expenditures and meet
such financial obligations as they come due. In the event such capital resources
are not available to us, or we choose to preserve our Credit Facility more for
acquisitions, our drilling and other activities may be curtailed.
Liquidity
We had cash and cash equivalents at June 30, 2002 of $704,849 consisting
primarily of short-term money market investments, as compared to $793,287 at
December 31, 2001. Our working capital surplus was $4.8 million at June 30,
2002, as compared to $682,065 at December 31, 2001. Our ratio of current assets
to current liabilities was 2.03:1 at June 30, 2002 compared to 1.1:1 at December
31, 2001. At June 30, 2002, borrowings outstanding under our Credit Facility
totaled $16 million compared to $10.0 million outstanding at December 31, 2001.
Our increases in working capital surplus and current ratio at June 30, 2002
resulted primarily from higher account receivable balances that resulted from
higher prices for our production compared to December 2001 and lower accrued
liabilities.
Cash Flows
Cash flows provided by operations were $2.4 million and $17.0 million for
the six months ended June 30, 2002 and 2001, respectively. The decrease in cash
flows provided by operations is primarily due to a decrease in net
15
income from $9.5 million in 2001 to $0.6 million for the same period in 2002.
For the six months ended June 30, 2002 working capital usage totaled $4.3
million ($3.7 million excluding the underaccrual adjustment) compared to a
working capital surplus of $2.6 million for the same period in 2001. Operating
cash flows, before changes in working capital, were $6.7 million ($6.1 million
excluding the underaccrual adjustment) and $14.4 million for the six months
ended June 30, 2002 and 2001, 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 was comprised of capital expenditures only
and totaled $8.6 million for the six months ended June 30, 2002 compared to $8.2
million used in the same period of 2001. We expended $3.5 million in our
drilling operations resulting in the drilling of 5 gross (2.1785 net) wells
during the 2002 year-to-date period as compared to 6 gross (3.2738 net) wells
during the same period in 2001. Since June 30, 2002, we have drilled one
successful gross well and currently one gross well is drilling. In addition to
capital expenditures for drilling operations, approximately $1.4 million was
incurred to purchase additional interests in our Gato Creek and Jericho
properties, $1.0 million was incurred on currently producing properties and $1.6
million was expended on land and seismic activities. The remaining cost
capitalized to oil and natural gas properties was internal G&A and interest of
approximately $1.1 million.
Cash provided by financing activities totaled $6.1 million for the six
months ended June 30, 2002 and included borrowings of $6.5 million and
repayments of $0.5 million under our Credit Facility. Other financing activities
included net proceeds from the exercise of stock options of $67,666. For the six
months ended June 30, 2001, cash used in financing activities totaled $2.6
million, which included borrowings of $1.0 million and repayments of $4,000,000,
as well as proceeds from the exercise of stock options of $390,801.
CREDIT FACILITY
During the first half of 2002, we had net borrowings of $6.0 million
bringing our outstanding debt balance to $16.0 million under our Credit Facility
at June 30, 2002. Borrowings under the Credit Facility bear interest at a rate
equal to prime plus 0.50% or LIBOR plus 2.5%. In August 2002, our borrowing
base was increased from $19 million to $25 million. In addition, the maturity
date was extended to October 6, 2004 with no automatic monthly reductions. We
expect the next borrowing base redetermination to be during the first quarter of
2003. The Credit Facility is secured by substantially all of our assets.
The 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, and engaging in
merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in
the agreement, of the Company for the four fiscal quarters then ended to (b) our
consolidated interest expense for the four fiscal quarters then ended, to not be
less than 3.5 to 1.0. The Working Capital ratio requires that the amount of our
consolidated current assets less our consolidated liabilities, as defined in the
agreement, be at least $1.0 million. The Allowable Expenses ratio requires that
(a) the aggregate amount of our 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) our year to date consolidated oil and gas
revenue, net of hedging activity, for the period from January 1 of such year
through the fiscal quarter then ended, to be less than .40 to 1.0. At June 30,
2002, we were in compliance with the above-mentioned covenants.
TAX MATTERS
At December 31, 2001, we had cumulative net operating loss carryforwards
("NOLs") for federal income tax purposes of approximately $18.2 million that
will begin to expire in 2012. We anticipate that all of these NOLs will be
utilized in connection with federal income taxes payable in the future. In the
fourth quarter of 2001, we reversed the previous valuation allowance that offset
our deferred tax assets. To the extent that we have financial statement income
in the future, we will require a tax provision in our consolidated statement of
operations. Based on anticipated
16
results for the year ending December 31, 2002 using current assumptions, we
estimate that our effective rate for 2002 will be approximately 36%.
NOLs assume that certain items, primarily intangible drilling costs, have
been written off for tax purposes in the current year. However, we have not made
a final determination if an election will be made to capitalize all or part of
these items for tax purposes in the future.
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 cash flow, capital
resources and liquidity to support working capital and/or capital expenditure
requirements, reinvestment of cash flows, the use of NOLs, tax rates, the
outcome of litigation, the resolution of title matters 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,
environmental and title 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.
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 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
outstanding borrowings at June 30, 2002 and a floating interest rate of 4.36%, a
10% change in the interest rate would result in an increase or decrease of
interest expense of approximately $66,600 on an annual basis.
In the normal course of business we enter into hedging transactions,
including commodity price collars, swaps and floors, to mitigate our exposure to
commodity price movements, but not for trading or speculative purposes. Due to
the instability of prices and to achieve a more predictable cash flow, we may
put in place a hedge on a portion of our production. While the use of these
arrangements may limit the benefit to us of increases in the price of oil and
natural gas it also limits the downside risk of adverse price movements.
Currently, there are no hedging activities in place for any future periods.
17
PART II - OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS
From time to time we are a party to various legal proceedings arising in
the ordinary course of business. While the outcome of lawsuits cannot be
predicted with certainty, we are not currently a party to any proceeding that we
believe, if determined in a manner adverse to us, could have a potential
material adverse effect on our financial condition, results of operations or
cash flows except for the litigation described below. We do not believe that the
ultimate outcome of this litigation will have a material adverse effect on us.
In October 2001, the Company was sued by certain mineral owners seeking to
cancel a portion of our Mew lease, upon which the Company and its partners
drilled and completed the Mew No. 1 well in Duval County, Texas. The suit names
the Company, Santos USA and Mark Smith, an independent landman, as Defendants,
and is filed in the 229th Judicial District Court of Duval County, Texas. The
suit seeks a declaratory judgment to set aside certain quitclaim deeds between
the Mew lessors that were intended to result in a partition of the mineral
estate between the various members of the Mew family in the land where the well
is located and other lands. The pleadings allege failure of consideration,
fraud, failure to consummate the partition, bad faith trespass and conversion.
As part of the leasing effort for the prospect, some members of the Mew family
had sought to partition their minerals under the tracts where they owned the
surface in full. The Mew heirs, from whom the Company acquired leases, could
lose a portion of their mineral interest if the quitclaim deeds are set aside.
Were this to happen, it could have the effect of voiding the Company's leases as
to an undivided one-third of the unit acreage for the Mew well and the Mew
lease. Plaintiffs seek unspecified actual and exemplary damages against the
Company and Santos arising out of alleged fraud committed by the Company and
Mark Smith. They also seek damages from Santos for the value of the oil and
natural gas produced and saved from the Mew well, or alternatively, for the
value of the oil and natural gas produced less the cost of drilling, completing
and operating the well. The Company has a 12.5% working interest in the well. As
of June 30, 2002, the Mew well has produced $7.3 million in net revenue and has
cost $2.6 million to drill, complete and operate. Estimated remaining gross
proved reserves are 53.6 MBbls and 3.9 Bcf. The Company has filed an answer in
the case and intends to vigorously defend its position that the Mew lease is
valid and subsisting in its entirety. Santos has filed a plea of abatement
asking that the case be dismissed for failure to join necessary and
indispensable parties. Pursuant to Santos' motion, certain additional defendants
have been joined in the case. At this point, it is not possible to determine the
ultimate outcome of this litigation or the exposure, if any, the Company may
have.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of litigation, the Company believes
there is no question that it acted in good faith and intends to vigorously
defend its position. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. Due to the uncertainty of the
final outcome, the Company has ceased to record revenue from the properties as
of August 1, 2001, which net to the Company averaged approximately 1.4 Mmcfe/d
of production at the time the well was shut-in. In addition, the Company removed
associated reserves of 1.4 Bcfe from its total proved reserves. The Company
believes this potential loss is not material to its financial condition or
results of operations.
18
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 6, 2002.
(B) Set fourth below are the results of the voting with respect to each matter
acted upon:
Broker
For Against Withheld Abstain Non Votes
--- ------- -------- ------- ---------
Election of Directors:
Vincent S. Andrews 7,796,962 801,498
Joseph R. Musolino 7,796,962 801,498
Nils P. Peterson 7,796,962 801,496
Approval of the
Appointment of Arthur
Andersen LLP as
Independent Public
Accountants 7,154,017 1,416,709 27,734
In addition to the election of the directors indicated above, the terms of the
following directors continued as directors following the meeting: John W. Elias,
John Sfondrini, Stanley S. Raphael and Robert W. Shower.
ITEM 5 - OTHER INFORMATION........................................ None
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K.........................
19
(A) EXHIBITS. The following exhibits are filed as part of this report:
INDEX TO EXHIBITS
Exhibit No.
- -----------
+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 -- 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.
(Incorporated by Reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 31, 2000).
+4.2 -- Amendment No. 1 and Waiver dated as of November 11, 2001 by and
among the lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for such
Lenders, Edge Petroleum Corporation, Edge Petroleum Exploration
Company, and Edge Petroleum Operating Company, Inc. (collectively,
the "Borrowers"), as borrowers under the Second Amended and Restated
Credit Agreement. (Incorporated by Reference from exhibit 4.2 to the
Company's Annual Report on Form 10K for the annual period ended
December 31, 2001).
+4.3 -- 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. (Incorporated by Reference from
exhibit 4.6 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 31, 2000).
+4.4 -- Letter Agreement dated March 23, 2001 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. (Incorporated by Reference from
exhibit 4.5 to the Company's Annual Report on Form 10K for the
annual period ended December 31, 2000).
20
+4.5 -- Letter Agreement dated September 21, 2001 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. (Incorporated by Reference from
exhibit 4.6 to the Company's Quarterly Report on Form 10Q for the
quarterly period ended September 30, 2001).
+4.6 -- Letter Agreement dated January 18, 2002 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. (Incorporated by Reference from
exhibit 4.6 to the Company's Annual Report on Form 10K for the
annual period ended December 31, 2001).
*4.7 -- Letter Agreement dated August 9, 2002 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.
+4.8 -- 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).
+4.9 -- 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).
+4.10 -- 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 -- 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)).
+10.5 -- 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).
+10.6 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of July 27, 1999, as amended March 1, 2001.
(Incorporated by reference from exhibit 10.6 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended June
30, 2001).
21
+10.7 -- 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 for the
quarterly period ended September 30, 1999).
+10.8 -- 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 for the
quarterly period ended September 30, 1999).
+10.9 -- 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 for the quarterly period ended September 30, 1999).
+10.10 -- 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/A for the quarterly period ended March 31, 1999).
+10.11 -- Edge Petroleum Corporation Amended and Restated Elias Stock
Incentive Plan. (Incorporated by reference from exhibit 4.5 to the
Company's Registration Statement on Form S-8 filed May 30, 2001
(Registration No. 333-61890)).
+10.12 -- Form of Edge Petroleum Corporation John W. Elias Non-Qualified
Stock Option Agreement (Incorporated by reference from exhibit 4.6
to the Company's Registration Statement on Form S-8 filed May 30,
2001 (Registration No. 333-61890)).
- ------------------
* Filed herewith.
+ Incorporated by reference as indicated.
(B) Reports on Form: The Company filed the following report on
Form:
The Company filed with the Securities and Exchange Commission, a Current
Report on Form dated July 18, 2002, that reported a change in auditors.
22
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 8/14/02 /s/ John W. Elias
-----------------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board
Date 8/14/02 /s/ Michael G. Long
-----------------------------------------
Michael G. Long
Senior Vice President and
Chief Financial and Accounting Officer
23
INDEX TO EXHIBITS
Exhibit No.
- -----------
+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 -- 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.
(Incorporated by Reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 31, 2000).
+4.2 -- Amendment No. 1 and Waiver dated as of November 11, 2001 by and
among the lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for such
Lenders, Edge Petroleum Corporation, Edge Petroleum Exploration
Company, and Edge Petroleum Operating Company, Inc. (collectively,
the "Borrowers"), as borrowers under the Second Amended and Restated
Credit Agreement. (Incorporated by Reference from exhibit 4.2 to the
Company's Annual Report on Form 10K for the annual period ended
December 31, 2001).
+4.3 -- 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. (Incorporated by Reference from
exhibit 4.6 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 31, 2000).
+4.4 -- Letter Agreement dated March 23, 2001 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. (Incorporated by Reference from
exhibit 4.5 to the Company's Annual Report on Form 10K for the
annual period ended December 31, 2000).
24
+4.5 -- Letter Agreement dated September 21, 2001 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. (Incorporated by Reference from
exhibit 4.6 to the Company's Quarterly Report on Form 10Q for the
quarterly period ended September 30, 2001).
+4.6 -- Letter Agreement dated January 18, 2002 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. (Incorporated by Reference from
exhibit 4.6 to the Company's Annual Report on Form 10K for the
annual period ended December 31, 2001).
*4.7 -- Letter Agreement dated August 9, 2002 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.
+4.8 -- 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).
+4.9 -- 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).
+4.10 -- 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 -- 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)).
+10.5 -- 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).
+10.6 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of July 27, 1999, as amended March 1, 2001.
(Incorporated by reference from exhibit 10.6 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended June
30, 2001).
25
+10.7 -- 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).
+10.8 -- 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).
+10.9 -- 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).
+10.10 -- 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).
+10.11 -- Edge Petroleum Corporation Amended and Restated Elias Stock
Incentive Plan. (Incorporated by reference from exhibit 4.5 to the
Company's Registration Statement on Form S-8 filed May 30, 2001
(Registration No. 333-61890)).
+10.12 -- Form of Edge Petroleum Corporation John W. Elias Non-Qualified
Stock Option Agreement (Incorporated by reference from exhibit 4.6
to the Company's Registration Statement on Form S-8 filed May 30,
2001 (Registration No. 333-61890)).
- ------------------
* Filed herewith.
+ Incorporated by reference as indicated.
26