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, 1999
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 4, 1999
------------ ------------------------------
Common Stock 9,158,667
<PAGE>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------------------------------------------
June 30, December 31,
1999 1998
---------------- ----------------
ASSETS (Unaudited)
CURRENT ASSETS:
<S> <C> <C>
Cash and cash equivalents $ 436,110 $ 272,428
Accounts receivable, trade 2,685,850 2,237,113
Accounts receivable, joint interest owners, net 996,231 2,215,096
Accounts receivable, related parties 207,859 228,922
Other current assets 248,268 313,631
--------- ---------
Total current assets 4,574,318 5,267,190
PROPERTY AND EQUIPMENT, Net - full cost method of accounting
for oil and natural gas properties 46,784,544 47,258,993
INVESTMENT IN FRONTERA 3,867,232 3,744,935
OTHER ASSETS 7,789 7,789
---------- ----------
TOTAL ASSETS $ 55,233,883 $ 56,278,907
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 1,456,422 $ 2,948,791
Accrued liabilities 2,610,988 3,779,881
Accrued interest payable 55,156 93,880
Current portion of long-term debt 3,150,000 6,700,000
--------- ---------
Total current liabilities 7,272,566 13,522,552
LONG-TERM DEBT 4,000,000 5,800,000
--------- ---------
Total liabilities 11,272,566 19,322,552
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, $.01par value; 5,000,000 shares authorized; none outstanding
Common stock, $.01par value; 25,000,000 shares authorized; 9,158,667
and 7,758,667 shares issued and outstanding at June 30, 1999 and
December 31, 1998, respectively 91,586 77,586
Additional paid-in capital 55,137,609 47,769,159
Retained earnings (deficit) (9,943,851) (9,398,410)
Unearned compensation - restricted stock (1,324,027) (1,491,980)
---------- ----------
Total stockholders' equity 43,961,317 36,956,355
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 55,233,883 $ 56,278,907
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
2
<PAGE>
<TABLE>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
- --------------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
1999 1998 1999 1998
<S> <C> <C> <C> <C>
OIL AND NATURAL GAS REVENUES $ 4,189,449 $ 3,849,045 $ 7,731,637 $ 7,634,711
OPERATING EXPENSES:
Lifting costs 487,242 558,754 966,370 928,813
Severance and ad valorem taxes 334,530 312,593 687,219 613,718
Depletion, depreciation and amortization 2,410,543 1,713,437 4,313,303 2,900,023
General and administrative expenses 1,097,939 1,050,516 2,099,758 1,916,827
Unearned compensation expense 83,977 176,456 167,953 331,508
--------- --------- --------- ---------
Total operating expenses 4,414,231 3,811,756 8,234,603 6,690,889
--------- --------- --------- ---------
OPERATING INCOME (LOSS) (224,782) 37,289 (502,966) 943,822
OTHER INCOME AND EXPENSE:
Interest expense (29,860) (12,535) (68,186) (12,617)
Interest income 14,689 56,049 25,711 102,259
--------- --------- --------- ---------
NET INCOME (LOSS) BEFORE INCOME TAX EXPENSE AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (239,953) 80,803 (545,441) 1,033,464
INCOME TAX EXPENSE (33,981) (367,862)
---------- --------- --------- ---------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE (239,953) 46,822 (545,441) 665,602
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 1,780,835
---------- -------- ----------- -----------
NET INCOME (LOSS) $ (239,953) $ 46,822 $ (545,441) $ 2,446,437
========== ======== ========== ===========
BASIC EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of accounting change $ (0.03) $ 0.01 $ (0.07) $ 0.08
Cumulative effect of accounting change 0.23
------- ------ ------- ------
Basic earnings (loss) per share $ (0.03) $ 0.01 $ (0.07) $ 0.31
======= ====== ======= ======
DILUTED EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of accounting change $ (0.03) $ 0.01 $ (0.07) $ 0.08
Cumulative effect of accounting change 0.23
------- ------ ------- ------
Diluted earnings (loss) per share $ (0.03) $ 0.01 $ (0.07) $ 0.31
======= ====== ======= ======
BASIC WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 8,589,312 7,771,711 8,176,223 7,771,558
========= ========= ========= =========
DILUTED WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 8,589,312 7,804,165 8,176,223 7,803,393
========= ========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
3
<PAGE>
<TABLE>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited)
- ------------------------------------------------------------------------------------------------------------------------------------
Unearned
Common Stock Additional Compensation- Total
------------------------- Paid-in Retained Restricted Stockholders'
Shares Amount Capital Earnings(Deficit) Stock Equity
---------- -------- ------------ ----------------- -------------- --------------
BALANCE,
<S> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1999 7,758,667 $ 77,586 $ 47,769,159 $(9,398,410) $ (1,491,980) $36,956,355
Private common stock offering,
net of offering costs of $230,050 1,400,000 14,000 7,368,450 7,382,450
Unearned compensation expense 167,953 167,953
Net loss (545,441) (545,441)
---------- --------- ------------ ------------ ------------- ------------
BALANCE,
June 30, 1999 9,158,667 $ 91,586 $ 55,137,609 $(9,943,851) $ (1,324,027) $ 43,961,317
========== ========= ============ ============ ============= ============
</TABLE>
See accompanying notes to consolidated financial statements.
4
<PAGE>
<TABLE>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
- -----------------------------------------------------------------------------------------------------------
Six Months Ended
June 30,
------------- --------------
1999 1998
CASH FLOWS FROM OPERATING ACTIVITIES:
<S> <C> <C>
Net income (loss) $ (545,441) $ 2,446,437
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Cumulative effect of accounting change (1,780,835)
Depletion, depreciation and amortization 4,313,303 2,900,023
Deferred income taxes 367,862
Unearned compensation expense 167,953 331,508
Changes in assets and liabilities:
Accounts receivable, trade (448,737) 49,492
Accounts receivable, joint interest owners, net 1,218,865 1,655,515
Accounts receivable, related parties 21,063 146,644
Other current assets 65,363 (134,085)
Other assets 9,443
Accounts payable, trade (1,492,369) 242,654
Accounts payable, related party (40,000)
Accrued liabilities (1,168,893) 85,543
Accrued interest payable (38,724)
--------- ---------
Net cash provided by operating activities 2,092,383 6,280,201
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment purchases (5,487,573) (19,961,191)
Proceeds from the sale of oil and natural gas properties 1,648,719 2,735,569
Investment in Frontera (122,297)
---------- -----------
Net cash used in investing activities (3,961,151) (17,225,622)
---------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from private offering, net of offering cost 7,382,450
Proceeds (payment) on notes payable (5,350,000) 8,000,000
--------- ---------
Net cash provided by financing activities 2,032,450 8,000,000
--------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 163,682 (2,945,421)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 272,428 3,777,950
--------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 436,110 $ 832,529
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized $ 68,584 $ 3,696
Issuance of restricted stock 144,017
</TABLE>
See accompanying notes to consolidated financial statements.
5
<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 (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 the Company believes that the disclosures are
adequate to make the information presented not misleading. Certain prior year
amounts have been reclassified to conform to the current year presentation. Such
reclassifications do not affect net income (loss). These financial statements
should be read in conjunction with the Company's audited consolidated financial
statements included in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998.
Accounting Change - The Company uses the full-cost method of accounting
for its oil and natural gas properties. Under this method, all acquisition,
exploration and development costs that are directly attributable to the
Company's acquisition, exploration and development activities are capitalized in
a "full-cost pool" as incurred. In the second quarter of 1998 and effective
January 1, 1998, the Company changed its method of accounting for internal
geological and geophysical ("G&G") costs to one of capitalization of such costs,
which are directly attributable to acquisition, exploration and development
activities, to oil and natural gas properties. Prior to the change the Company
expensed these costs as incurred. The Company believes the accounting change
provides for a better matching of revenues and expenses and enhances the
comparability of it's financial statements with those of other companies that
follow the full-cost method of accounting. The $1,780,835 (or $0.23 basic and
diluted earnings per share) cumulative effect of the change in prior years
(after reduction for income taxes of $958,910) is included in income for the six
months ended June 30, 1998.
Accounting Pronouncements
Derivatives - In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 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 137"). SFAS 137 delays the
effective date for implementation of SFAS 133 for one year making SFAS 133
effective for all fiscal quarters of all fiscal years beginning after June 15,
2000. Retroactive application to periods prior to adoption is not allowed. The
Company has not quantified the impact of adoption on its financial statements or
the date it intends to adopt. Earlier application of SFAS 133 is encouraged, but
not prior to the beginning of any fiscal quarter that begins after issuance of
the statement.
6
<PAGE>
2. LONG TERM DEBT
During July 1995, the Company entered into a revolving credit facility (the
"Revolving Credit Facility") with a bank to finance temporary working capital
requirements. The Revolving Credit Facility provided up to $20 million in
borrowings limited by a borrowing base, as defined by the Revolving Credit
Facility. The Revolving Credit Facility provided for interest at the lender's
prime rate plus 0.75%. The borrowing base was subject to review by the bank on a
quarterly basis and could be adjusted subject to the provisions of the Revolving
Credit Facility. Effective April 1, 1998, the Company amended and restated its
Revolving Credit Facility to provide a revolving line of credit of up to $100
million bearing interest at a rate equal to prime or LIBOR plus 1.5% - 2%
depending on the level of borrowing base utilization. The Company's initial
borrowing base authorized by the banks was approximately $15 million. The
Revolving Credit Facility is secured by substantially all the assets of the
Company.
Effective September 29, 1998, the Company had its borrowing base
redetermined and amended its Revolving Credit Facility. The initial borrowing
base authorized by the bank was $15 million. Beginning October 1, 1998, and on
the first day of each month thereafter, the borrowing base was required to be
reduced by $550,000.
Effective March 1, 1999, the Company and the Bank amended the Revolving
Credit Facility to include the following terms; 1) the initial borrowing base
was $12 million comprised of a two tranche financing of a $9 million Revolving
Credit Facility and a $3 million term facility, 2) Beginning May 1, 1999, and on
the first day of each month thereafter, the Revolving Credit Facility borrowing
base was required to be reduced by $400,000, 3) 75% of prospect sales will be
used to pay down the term facility with the remaining unpaid term facility
balance maturing on August 31, 1999. On May 8, 1999, from proceeds generated by
the Private Offering (see Note 5), the Company repaid the $3 million term loan
in addition to $1.9 million of the Revolving Credit Facility. Total outstanding
long-term debt(including current portion) as of June 30, 1999 was $7.15 million.
Effective July 1, 1999, the Company had its borrowing base redetermined. The
initial borrowing base authorized by the bank is $8.8 million. Beginning August
1, 1999, and on the first day of each month thereafter, the borrowing base is
required to be reduced by $400,000. Total borrowing available under the
Revolving Credit Facility was approximately $1.65 million at June 30, 1999.
The Revolving Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of its 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 the Company's Tangible
Net Worth be at least 90% of the Company's 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. Interest will accrue at a rate of
LIBOR plus 1.75% - 2.75% depending on the borrowing base utilization. At June
30, 1999 the Company was in compliance with the above mentioned covenants.
3. EARNINGS PER SHARE
The Company accounts for earnings per share in accordance with Statement of
Financial Accounting Standard 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 using the treasury stock method.
7
<PAGE>
The following is presented as a reconciliation of the numerators and
denominators of basic and diluted earnings per share computations, in accordance
with SFAS No. 128.
<TABLE>
Three Months Ended
--------------------------------------------------------------------------------
June 30, 1999 June 30, 1998
------------------------------------- -------------------------------------
Income Shares Per-Share Income Shares Per-Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- --------- ----------- ------------- ---------
Basic EPS
Income (loss) available to
<S> <C> <C> <C> <C> <C> <C>
common stockholders $ (239,953) 8,589,312 $(0.03) $ 46,822 7,771,711 $ 0.01
Effect of Dilutive Securities
Common stock options 32,454
------------ --------- ------- ----------- --------- -------
Diluted EPS
Income (loss) available to
common stockholders $ (239,953) 8,589,312 $(0.03) $ 46,822 7,804,165 $ 0.01
============ ========= ======= =========== ========= =======
Six Months Ended
--------------------------------------------------------------------------------
June 30, 1999 June 30, 1998
------------------------------------- -------------------------------------
Income Shares Per-Share Income Shares Per-Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- --------- ----------- ------------- ---------
Basic EPS
Income (loss) available to
<S> <C> <C> <C> <C> <C> <C>
common stockholders $ (545,441) 8,176,223 $(0.07) $2,446,437 7,771,558 $ 0.31
Effect of Dilutive Securities
Common stock options 31,835
----------- --------- ------- ----------- --------- -------
Diluted EPS
Income (loss) available to
common stockholders $ (545,441) 8,176,223 $(0.07) $2,446,437 7,803,393 $ 0.31
=========== ========= ======= =========== ========= =======
</TABLE>
4. INCOME TAXES
The Company accounts for income taxes under the provisions of
Statement of Financial Accounting Standards No. 109 "Accounting for Income
Taxes," ("SFAS No. 109") which provides for an asset and liability approach for
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 differences between financial
statement carrying amounts of assets and liabilities and their respective tax
bases. Due to the Company incurring a net loss for the three and six month
periods ended June 30, 1999 and due to the Company having significant deferred
tax assets, no tax benefit (expense) was recorded. Due to the uncertainty of the
Company's ability to become profitable in the future, an allowance has been
provided to offset the tax benefits of certain tax assets. Should the Company
have net income in future periods income tax expense will be recorded upon
utilization of available deferred tax assets.
5. EQUITY
On May 7, 1999, the Company completed a "Private Offering" of 1,400,000
shares of common stock at a price of $5.40 per common share. The Company also
issued warrants, which were purchased for $0.125 per warrant, to acquire an
additional 420,000 shares of common stock at $5.35 per share and are exercisable
through May 6, 2004. At the election of the Company, the warrants may be called
at a redemption price of $0.01 per warrant at any time after any date at which
the average daily per share closing bid price for the immediately proceeding 20
consecutive trading days exceeds $10.70. No warrants have been exercised as
of June 30, 1999. Total proceeds, net of offering costs, were approximately $7.4
million of which $4.9 million was used to repay debt under the Revolving Credit
Facility with the remainder being utilized to satisfy working capital
requirements and fund a portion of the Company's future exploration program.
8
<PAGE>
Effective May 21, 1999, the Company amended and restated it's Nonqualified
Stock Option Plan. In conjunction with the amendment of the plan, the Company
exchanged, on a voluntary basis, 594,733 outstanding Nonqualified Stock options
of certain employees and Directors of the Company and for 326,700 new common
stock options. The grant price of the replacement options was $7.0625, which
approximates the fair market value on the date of grant. The reissued 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, the
Company also elected to issue 114,000 new ten-year common stock options to
employees, which vest 100% on May 21, 2001. The grant price of the new options
was $7.0625, which approximates the fair market value on the date of grant. On
June 1, 1999 the Company issued 21,000 10 year common stock options to
non-employee directors with an exercise price of $7.28 per share vesting 100% on
June 1, 2001.
The Company accounts for Stock Based Compensation in accordance with
Financial Accounting Standards Board Statement No. 123 - "Accounting for Stock
Based Compensation," ("SFAS No. 123"). Under SFAS No. 123, the Company is
permitted to either record expenses for stock options and other employee
compensation plans based on their fair value at the date of grant or to continue
to apply its 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. The Company
elected to continue following APB No. 25.
9
<PAGE>
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 the Company's
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 the Company's audited consolidated financial statements included in the
Company's annual report on Form 10-K for the year ended December 31, 1998.
Unless otherwise indicated by the context, references herein to the "Company"
mean Edge Petroleum Corporation, a Delaware corporation that is the registrant,
and its subsidiaries.
Overview
Edge Petroleum Corporation is an independent energy company engaged in
the exploration, development and production of oil and natural gas. Edge
conducts its operations primarily along the onshore Gulf Coast with its primary
emphasis in South Texas and South Louisiana where it currently controls
interests in excess of 192,000 gross acres under lease and option. The Company
explores for oil and natural gas by emphasizing an integrated application of
highly advanced data visualization techniques and computerized 3-D seismic data
analysis to identify potential hydrocarbon accumulations. The Company believes
its approach to processing and analyzing geophysical data differentiates it from
other independent exploration and production companies and is more effective
than conventional 3-D seismic data interpretation methods. The Company also
believes it maintains one of the largest databases of onshore South Texas Gulf
Coast 3-D seismic data of any independent oil and natural gas company, and is
continuously acquiring additional data within this core region.
The Company acquires 3-D seismic data by organizing and designing
regional data acquisition surveys for its proprietary use, as well as through
selective participation in regional non-proprietary 3-D surveys. The Company
negotiates seismic options for a majority of the areas encompassed by its
proprietary surveys, thereby allowing it to secure identified prospect leasehold
interests on a non-competitive, pre-arranged basis. In the Company's
non-proprietary 3-D survey areas, the Company's technical capabilities allow it
to rapidly and comprehensively evaluate large volumes of regional 3-D seismic
data, facilitating its ability to identify attractive prospects within a
surveyed region and to secure the corresponding leasehold interests ahead of
other industry participants.
The Company's extensive technical expertise has enabled it to internally
generate substantially all of its 3-D prospects drilled to date and to assemble
a large portfolio of 3-D based prospects for future drilling. The Company
pursues drilling opportunities that include a blend of shallower, normally
pressured reservoirs that generally involve moderate costs and risks as well as
deeper, over-pressured reservoirs that generally involve greater costs and
risks, but have higher economic potential. In recent years, the Company has
expanded its relative focus to increase its exposure to exploration
opportunities in the deeper geological section. The Company mitigates its
exposure to exploration costs and risk by conducting its operations with
industry partners, including major oil companies and large independents, that
generally pay a disproportionately greater share of seismic acquisition and, in
many instances, leasing and drilling costs than the Company. The Company may
seek to participate in an increased number of externally generated prospects,
including those in which the Company pays a disproportionate share of the cost,
depending upon the quality, size, price and other factors relating to such
prospects.
10
<PAGE>
The Company uses the full-cost method of accounting for its oil and
natural gas properties. Under this method, all acquisition, exploration and
development costs, including certain general and administrative costs that are
directly attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
capitalizes internal Geological and Geophysical ("G&G") costs that are directly
attributable to acquisition, exploration and development activities to oil and
natural gas properties. Total internal G&G costs capitalized during the three
months ended June 30, 1999 and 1998 were $505,148 and $654,777, respectively,
and during the six months ended June 30, 1999 and 1998 were $1,068,740 and
$1,194,742, respectively. The Company records depletion of its full-cost pool
using the unit of production method. Investments in unproved properties are not
subject to amortization until the proved reserves associated with the projects
can be determined or until impaired. To the extent that capitalized costs
subject to amortization in the full-cost pool (net of depletion, depreciation
and amortization and related deferred taxes) exceed the present value (using a
10% discount rate) of estimated future net after-tax cash flows from proved oil
and natural gas reserves, such excess costs are charged to operations. Once
incurred, an impairment of oil and natural gas properties is not reversible at a
later date. Impairment of oil and natural gas properties is assessed on a
quarterly basis in conjunction with the Company's quarterly filings with the
Security and Exchange Commission. At June 30, 1999, no full cost ceiling test
write down of oil and natural gas properties was necessary.
Due to the instability of oil and natural gas prices, the Company has
entered into, from time to time, price risk management transactions (e.g., swaps
and collars) for a portion of its 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 limits the benefit to the Company of
increases in the price of natural gas it also limits the downside risk of
adverse price movements. The Company's hedging arrangements apply to only a
portion of its production and provide only partial price protection against
declines in natural gas prices and limits potential gains from future increases
in prices. The Company accounts 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. During December 1998, the
Company entered into a fixed price swap for $1.957 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. This fixed price swap covers 13,000 MMbtu per day and is effective
beginning March 1, 1999 and expires on October 31, 1999. During April 1999, the
Company entered into an additional fixed price swap for $2.145 per MMbtu. This
fixed price swap covers 3,000 MMbtu per day and is effective beginning May 1,
1999 and expires on October 31, 1999. Total natural gas production hedged under
these arrangement was 1,366,000 MMbtu and 1,769,000 MMbtu, respectively for the
three-month and six-month periods ended June 30, 1999. Existing swaps currently
cover approximately 76% of current daily production. During the six months ended
June 30, 1998, the Company had in place three natural gas commodity collars,
expiring on January 31, April 30, and June 30, 1998, respectively. These collars
covered 5,000-10,000 MMbtu per day, or approximately 45% of the Company's daily
production, with floating floor and ceiling prices ranging between $2.15 and
$3.15 per MMbtu. Total natural gas production hedged under these arrangements
was 1,060,000 MMbtu and 1,510,000 MMbtu, respectively, for the three-month and
six-month periods ended June 30, 1998. Included within natural gas revenues for
the three and six month periods ended June 30, 1999 and 1998 was ($258,534) and
$30,000 and ($116,188) and $66,700, respectively, representing (losses) and
gains from swap and collar activity.
The Company's revenue, profitability and future rate of growth and
ability to borrow funds or obtain additional capital, and the carrying value of
its properties, are substantially dependent upon prevailing prices for oil and
natural gas. These prices are dependent upon numerous factors beyond the
Company's control, such as economic, political and regulatory developments and
competition from other sources of energy. Even though oil and natural gas
commodity prices have shown signs of recent recovery, a substantial or extended
decline in oil and natural gas prices could have a material adverse effect on
the Company's financial condition, results of operation and access to capital,
as well as the quantities of oil and natural gas reserves that the Company may
economically produce.
11
<PAGE>
RESULTS OF OPERATIONS
Three Months Ended June 30, 1999 Compared to the Three Months Ended June 30,
1998
Revenue and Production
Oil and natural gas revenues for the three months ended June 30, 1999
increased 9% from $3.8 million to $4.2 million, as compared to the three months
ended June 30, 1998. Production volumes for oil and condensate for the three
months ended June 30, 1999 increased 52% from 39 MBbls to 60 MBbls, as compared
to the three months ended June 30, 1998. The increase in oil and condensate
production during the three months ended June 30, 1999 increased revenues by
$239,000 (based on 1998 comparable quarter average prices), further increased by
a 9% increase in the average oil and condensate sales price which increased
revenues by $65,000 (based on current quarter production). Production volumes
for natural gas for the three months ended June 30, 1999 increased 9% from 1,520
MMcfs to 1,660 MMcfs, as compared to the three months ended June 30, 1998. The
increase in natural gas production during the three months ended June 30, 1999
increased revenues by $312,000, offset by an 8% decrease in the average natural
gas sales price which decreased revenues by $274,000. The increase in oil and
natural gas production was primarily due to 23 gross (6.05 net) new successful
exploratory and development wells being drilled and completed since June 30,
1998 offset by normal production declines from existing wells. As described
within hedging activities above, included within natural gas revenues for the
three months ended June 30, 1999 and 1998 was ($258,534) and $30,000,
respectively, representing (losses) and gains from swap and collar activity.
Hedging activities decreased the effective natural gas sales price by
approximately $0.16 per Mcf (or 7%) and increased the effective natural gas
price by approximately $0.02 per Mcf (or 1%) for the three-months ended June 30,
1999 and 1998, respectively.
The following table sets forth certain operational data of the Company
for the periods presented:
<TABLE>
Three Months Ended 1999 Period Compared
June 30, to 1998 Period
---------------------------- ------------------------
Increase % Increase
1999 1998 (Decrease) (Decrease)
Production volumes:
<S> <C> <C> <C> <C>
Oil and condensate (Bbls) 59,641 39,351 20,290 52%
Natural gas (Mcf) 1,660,259 1,520,368 139,891 9%
Natural gas equivalents (Mcfe) 2,018,105 1,756,474 261,631 15%
Average sales prices:
Oil and condensate ($ per Bbl) $ 12.87 $ 11.78 $ 1.09 9%
Natural gas ($ per Mcf) $ 2.06 $ 2.23 $ 0.17 8%
Natural gas equivalents ($ per Mcfe) $ 2.08 $ 2.19 $ 0.11 5%
Operating revenues:
Oil and condensate $ 767,402 $ 463,658 $ 303,744 66%
Natural gas 3,422,047 3,385,387 36,660 1%
----------- ----------- ----------
Total $ 4,189,449 $ 3,849,045 $ 340,404 9%
=========== =========== ==========
</TABLE>
Costs and Operating Expenses
Lifting costs for the three months ended June 30, 1999 decreased 13%
from $558,754 to $487,242 as compared to the three months ended June 30, 1998
due primarily to operating efficiencies in the field. Lifting costs were $0.24
per Mcfe and $0.32 per Mcfe for the three-month periods ended June 30, 1999 and
1998, respectively.
Depletion, depreciation and amortization expense ("DD&A") for the three
months ended June 30, 1999 increased 41% from $1,713,437 to $2,410,543, as
compared to the three months ended June 30, 1998. Included within DD&A for the
three-month periods ended June 30, 1999 and 1998 was $2.2 million and $1.5
million, respectively, representing depletion expense of oil and natural gas
property,
12
<PAGE>
which increased by 47%. Increased oil and natural gas production
increased depletion expense by $228,000 and a 28% increase in the overall
depletion rate further increased depletion expense by $472,000. The increase in
the depletion rate was primarily attributable to abandonments of certain
projects, prospects and wells and dry holes drilled since June 30, 1998
contributing to an overall increase in finding cost. Depletion expense on a unit
of production basis for the three-month periods ended June 30, 1999 and 1998 was
$1.11 per Mcfe and $0.87 per Mcfe, respectively. The remaining decrease in DD&A
is due primarily to the amortization of deferred loan cost on the Credit
Facility which was fully amortized at March 31, 1999.
General and administrative expenses ("G&A") for the three months ended
June 30, 1999 increased 5% from $1,050,516 to $1,097,939, as compared to the
three months ended June 30, 1998. The increase in G&A was primarily attributable
to a $126,000 decrease in overhead and management fees received from various
management, operating and seismic agreements during the three months ended June
30, 1999. Overhead and management fees are recorded as a reduction of G&A and
were approximately $118,000 and $244,000 for the three months ended June 30,
1999 and 1998, respectively. General and administrative expenses on a unit of
production basis for the three-month periods ended June 30, 1999 and 1998 were
$0.54 per Mcfe and $0.60 per Mcfe, respectively.
Unearned compensation expense for the three months ended June 30, 1999
decreased from $176,456 to $83,977, as compared to the three months ended June
30, 1998. The decrease is due to the resignation of the former CEO and Chairman
of the Board during November of 1998 whereby he vested in his remaining
restricted stock grant. The Company charged to expense his unamortized unearned
compensation upon his resignation.
Interest expense for the three months ended June 30, 1999 was $29,860
as compared to $12,535 for the three months ended June 30, 1998. The total
amount of interest capitalized to oil and natural gas properties during the
three-month periods ended June 30, 1999 and 1998 was $120,685 and $65,484,
respectively. The increase in interest expense is due to the increase in the
weighted average long-term debt balance outstanding during the three months
ended June 30, 1999 compared to the three month period ended June 30, 1998.
Weighted average debt was $9.1 million for the three months ended June 30, 1999
compared to $4.4 million for the three months ended June 30, 1998.
Interest income for the three months ended June 30, 1999 decreased from
$56,049 to $14,689, as compared to the three months ended June 30, 1998. The
decrease in interest income is due to the overall reduction in invested funds.
Due to the Company incurring a net loss for the three-months ended June
30, 1999 and due to the Company having significant deferred tax assets, no tax
benefit (expense) was recorded. Due to the uncertainty of the Company's ability
to become profitable in the future an allowance has been provided to offset the
tax benefits of certain tax assets. Should the Company have net income in future
periods, income tax expense will be recorded upon utilization of available tax
assets. Tax expense for the three-months ended June 30, 1998 was $33,981.
For the three months ended June 30, 1999, the Company had an operating
loss of $(224,782) compared to operating income of $37,289 for the three month
period ended June 30, 1998, primarily reflecting increased DD&A offset by
increased oil and natural gas revenues resulting from increased oil and natural
gas production. The net loss was $(239,953) for the three months ended June 30,
1999 as compared to net income of $46,822 for the three-month period ended June
30, 1998.
The Six Months Ended June 30, 1999 Compared to the Six Months Ended June 30,
1998
Revenue and Production
Oil and natural gas revenues for the six months ended June 30, 1999
increased 1% from $7.6 million to $7.7 million, as compared to the six months
ended June 30, 1998. Production volumes for oil and condensate for the six
months ended June 30, 1999 increased 19% from 81 MBbls to 97 MBbls, as compared
to the six months ended June 30, 1998. The increase in oil and condensate
production increased revenues by $198,000 (based on 1998 comparable period
average prices) and an 8% decrease in average oil and condensate sales price
13
<PAGE>
decreased revenue by $94,000 (based on current year production). Production
volumes for natural gas increased 17% from 2,843 MMcfs to 3,329 MMcfs, as
compared to the six months ended June 30, 1998. The increase in natural gas
production increased revenues by $1.1 million, offset by a 15% decrease in
average natural gas sales price which decreased revenues by $1.1 million. The
increase in oil and natural gas production was due to 23 gross (6.05 net) new
successful exploratory and development wells being drilled and completed since
June 30, 1998 offset by normal production declines from existing wells. As
described within hedging activities above, included within natural gas revenues
for the six months ended June 30, 1999 and 1998 was $(116,188) and $66,700,
respectively, representing gains and (losses) from swap and collar
activity. Hedging activities decreased the effective natural gas sales price by
approximately $0.3 per Mcf (or 1%) and increased the effective natural gas price
by approximately $0.02 per Mcf (or 1%) for the six months ended June 30, 1999
and 1998, respectively.
The following table sets forth-certain operational data of the Company for
the periods presented:
<TABLE>
Six Months Ended 1999 Period Compared
June 30, to 1998 Period
---------------------------- ------------------------
Increase % Increase
1999 1998 (Decrease) (Decrease)
Production volumes:
<S> <C> <C> <C> <C>
Oil and condensate (Bbls) 97,051 81,492 15,559 19 %
Natural gas (Mcf) 3,328,682 2,843,391 485,291 17 %
Natural gas equivalents (Mcfe) 3,910,988 3,332,343 578,645 17 %
Average sales prices:
Oil and condensate ($ per Bbl) $ 11.78 $ 12.75 $ (0.97) (8)%
Natural gas ($ per Mcf) $ 1.98 $ 2.32 $ (0.34) (15)%
Natural gas equivalents ($ per Mcfe) $ 1.98 $ 2.29 $ (0.31) (14)%
Operating revenues:
Oil and condensate $ 1,143,421 $ 1,039,114 $ 104,307 10 %
Natural gas 6,588,216 6,595,597 (7,381) (0)%
----------- ----------- ----------
Total $ 7,731,637 $ 7,634,711 $ 96,926 1 %
=========== =========== ==========
</TABLE>
Costs and Operating Expenses
Lifting costs for the six months ended June 30, 1999 increased 4% from
$928,813 to $966,370, as compared to the six months ended June 30, 1998, due
primarily to increased oil and natural gas production offset by operating
efficiencies in the field. Lifting costs on a unit of production basis were
$0.25 per Mcfe and $0.28 per Mcfe for the six-month periods ended June 30, 1999
and 1998, respectively.
Depletion, depreciation and amortization expense ("DD&A") for the six
months ended June 30, 1999 increased 49% from $2,900,758 to $4,313,303, as
compared to the six months ended June 30, 1998. Included within DD&A for the
six-month periods ended June 30, 1999 and 1998 was $4 million and $2.6 million,
respectively, representing depletion expense of oil and natural gas property,
which increased by 54%. Increased oil and natural gas production increased
depletion expense by $446,000 and a 31% increase in the overall depletion rate
further increased depletion expense by $954,000. The increase in the depletion
rate was primarily attributable to abandonments of certain projects, prospects
and wells and dry holes drilled since June 30, 1998 contributing to an overall
increase in finding cost. Depletion expense on a unit of production basis for
the six-month period ended June 30, 1999 and 1998 was $1.01 per Mcfe and $0.77
per Mcfe, respectively.
General and administrative expenses for the six months ended June 30,
1999 increased 10% from $1,916,827 to $2,099,758, as compared to the six
months ended June 30, 1998. The increase in G&A was primarily attributable to a
$251,000 decrease in overhead and management fees billed under various
management, operating and seismic agreements during the six months ended June
30, 1999. Total overhead and management fees are recorded as a reduction of G&A
and were approximately $173,000 and $424,000, respectively, for the six-month
14
<PAGE>
periods ended June 30, 1999 and 1998. G&A on a unit of production basis for the
six-month periods ended June 30, 1999 and 1998 was $0.54 per Mcfe and $0.58 per
Mcfe, respectively.
Unearned compensation expense for the six months ended June 30, 1999
decreased from $331,508 to $167,953, as compared to the six months ended June
30, 1998. The decrease is due to the resignation of the former CEO and Chairman
of the Board during November of 1998 whereby he vested in his remaining
restricted stock grant. The Company charged to expense his unamortized unearned
compensation upon his resignation.
Interest expense for the six months ended June 30, 1999 was $68,186
compared to $12,617 for the six months ended June 30, 1998. The total amount of
interest capitalized to oil and natural gas properties was $346,282 and $65,484
for the six months ended June 30, 1999 and 1998, respectively. The increase in
interest expense is due to the increase in the weighted average long-term debt
balance outstanding during the six months ended June 30, 1999 compared to the
six month period ended June 30, 1998. Weighted average debt was $10.5 million
for the six months ended June 30, 1999 compared to $2.2 million for the six
months ended June 30, 1998.
Interest income for the six months ended June 30, 1999 was $25,711
compared to $102,259 for the six months ended June 30, 1998. The decrease in
interest income is due to the overall reduction in invested funds.
Due to the Company incurring a net loss for the six months ended June
30, 1999 and due to the Company having significant deferred tax assets, no tax
benefit (expense) was recorded. Due to the uncertainty of the Company's ability
to become profitable in the future, an allowance has been provided to offset the
tax benefits of certain tax assets. Should the Company have net income in future
periods income tax expense will be recorded upon the utilization of available
tax assets. Tax expense for the six months ended June 30, 1998 was $367,862.
For the six months ended June 30, 1999, the Company had an operating
loss of $(502,966) compared to operating income of $943,822 for the six months
ended June 30, 1998, primarily reflecting increased DD&A and G&A offset by
increased oil and natural gas revenues resulting from increased oil and natural
gas production. The net loss was $(545,441) for the six months ended June 30,
1999 compared to net income of $2.4 million, $665,602 before cumulative effect
of accounting change, for the six months ended June 30, 1998.
LIQUIDITY AND CAPITAL RESOURCES
On May 7, 1999, the Company completed a "Private Offering" of 1,400,000
shares of common stock at a price of $5.40 per common share. The Company also
issued warrants, which were purchased for $0.125 per warrant, to acquire an
additional 420,000 shares of common stock at $5.35 per share and are exercisable
through May 6, 2004. At the election of the Company, the warrants may be called
at a redemption price of $0.01 per warrant at any time after any date at which
the average daily per share closing bid price for the immediately proceeding 20
consecutive trading days exceeds $10.70. No warrants have been exercised as
of June 30, 1999. Total proceeds, net of offering costs, were approximately $7.4
million of which $4.9 million was used to repay debt under the Revolving Credit
Facility with the remainder being utilized to satisfy working capital
requirements and fund a portion of the Company's future exploration program.
The Company had cash and cash equivalents at June 30, 1999 of $436,110
consisting primarily of short-term money market investments, as compared to
$272,428 at December 31, 1998. Working capital (deficit) was $(2.7) million at
June 30, 1999, as compared to $(8.3) million at December 31, 1998.
Operating cash flow was approximately $3.9 million and $4.3 million for
the six-month periods ended June 30, 1999 and 1998, respectively. Operating cash
flow, a measure of performance for exploration and production companies,
15
<PAGE>
represents cash flows from operating activities prior to changes in assets and
liabilities. 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.
During the six months ended June 30, 1999, the Company continued to
reinvest a substantial portion of its cash flows to increase its 3-D project
portfolio, improve its 3-D seismic interpretation technology and fund its
drilling program. Capital expenditures during the six months ended June 30, 1999
were approximately $5.5 million as compared to $20 million during the same
period in 1998. The Company expended $2.5 million in its drilling operations
resulting in the drilling of gross 8 (3.19 net) wells during the six months
ended June 30, 1999 as compared to gross 50 (23.9 net) wells during the same
period in 1998. Two wells, spud prior to June 30, 1999, are currently drilling
or in the process of being completed, the Varn #2 located in South Louisiana and
the Evans #1 located in South Texas. Land and data acquisition expenditures were
$3.0 million and were largely attributable to its Nodosaria Embayment 3-D
Project Area in South Louisiana. Total capital expenditures for 1999 are
expected to be approximately $15 million.
Due to the Company's active exploration and development and technology
enhancement programs, the Company has experienced and expects to continue to
experience substantial working capital requirements. The Company intends to fund
its 1999 capital expenditures, commitments and working capital requirements
through cash flows from operations, available borrowings under its existing
Revolving Credit Facility, and to the extent necessary other financing
activities. To provide additional working capital the Company continues to
market a portion of its interest in various Company generated drill ready
prospects. Additionally, the Company is currently evaluating various financing
and refinancing options as well as divestitures of certain non-core and under
performing assets. The Company believes it will be able to generate capital
resources and liquidity sufficient to fund its capital expenditures and meet
such financial obligations as they come due. In the event such capital resources
are not available to the Company, its drilling and other activities may be
curtailed.
Revolving Credit Facility
During July 1995, the Company entered into a revolving credit facility
(the "Revolving Credit Facility") with a bank to finance temporary working
capital requirements. The Revolving Credit Facility provided up to $20 million
in borrowings limited by a borrowing base, as defined by the Revolving Credit
Facility. The Revolving Credit Facility provided for interest at the lender's
prime rate plus 0.75%. The borrowing base was subject to review by the bank on a
quarterly basis and could be adjusted subject to the provisions of the Revolving
Credit Facility. Effective April 1, 1998, the Company amended and restated its
Revolving Credit Facility to provide a revolving line of credit of up to $100
million bearing interest at a rate equal to prime or LIBOR plus 1.5% - 2%
depending on the level of borrowing base utilization. The Company's initial
borrowing base authorized by the banks was approximately $15 million. The
Revolving Credit Facility is secured by substantially all the assets of the
Company.
Effective September 29, 1998, the Company had its borrowing base
redetermined and amended its Revolving Credit Facility. The initial borrowing
base authorized by the bank was $15 million. Beginning October 1, 1998, and on
the first day of each month thereafter, the borrowing base was required to be
reduced by $550,000.
Effective March 1, 1999, the Company and the Bank amended the Revolving
Credit Facility to include the following terms; 1) the initial borrowing base
was $12 million comprised of a two tranche financing of a $9 million Revolving
Credit Facility and a $3 million term facility, 2) Beginning May 1, 1999, and on
the first day of each month thereafter, the Revolving Credit Facility borrowing
base is required to be reduced by $400,000, 3) 75% of prospect sales will be
used to pay down the term facility with the remaining unpaid term facility
balance maturing on August 31, 1999. On May 8, 1999, from proceeds generated by
the Private Offering, the Company repaid the $3 million term loan in addition to
16
<PAGE>
$1.9 million of the Revolving Credit Facility. Total outstanding long-term debt
as of June 30, 1999 was $7.15 million.
Effective July 1, 1999, the Company had its borrowing base
redetermined. The initial borrowing base authorized by the bank is $8.8 million.
Beginning August 1, 1999, and on the first day of each month thereafter, the
borrowing base is required to be reduced by $400,000. Total borrowing available
under the Revolving Credit Facility was approximately $1.65 million at June 30,
1999.
The Revolving Credit Facility provides for certain restrictions,
including but not limited to, limitations on additional borrowings and issues of
capital stock, sales of its 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 the Company's Tangible
Net Worth be at least 90% of the Company's 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. Interest will accrue at a rate of
LIBOR plus 1.75% - 2.75% depending on the borrowing base utilization. At June
30, 1999 the Company was in compliance with the above mentioned covenants.
Accounting Change
The Company uses the full-cost method of accounting for its oil and
natural gas properties. Under this method, all acquisition, exploration and
development costs that are directly attributable to the Company's acquisition,
exploration and development activities are capitalized in a "full-cost pool" as
incurred. In the second quarter of 1998 and effective January 1, 1998, the
Company changed its method of accounting for internal geological and geophysical
("G&G") costs to one of capitalization of such costs, which are directly
attributable to acquisition, exploration and development activities, to oil and
natural gas properties. Prior to the change the Company expensed these costs as
incurred. The Company believes the accounting change provides for a better
matching of revenues and expenses and enhances the comparability of it's
financial statements with those of other companies that follow the full-cost
method of accounting. The $1,780,835 (or $0.23 basic and diluted earnings per
share) cumulative effect of the change in prior years (after reduction for
income taxes of $958,910) is included in income for the six months ended June
30, 1998.
Year 2000
The Company has completed its assessment of the Year 2000 processing
issues of its internal technology systems, considering current financial and
accounting, production, land and geological computer systems and software
utilized by the Company. Due to the need for improved management reporting, the
Company is in the process of replacing its existing financial and accounting,
production and land applications with new software which is year 2000 compliant.
Implementation is expected to be completed on or before September 30, 1999 at a
total cost of approximately $235,000. As of June 30, 1999, the Company has
incurred approximately $180,000 converting to its new financial and accounting
system and software with a majority of the remaining cost to be incurred prior
to September 30, 1999. The Company expects the production and land applications
to be operational on or before September 30, 1999. These costs have been funded
from cash flows from operations and the cost of the new software and necessary
hardware upgrades have been capitalized. Future costs to address the Year 2000
issue are also expected to be funded from cash flows from operations, and the
future costs of new software and hardware upgrades are expected to be
capitalized. Based on assertions made by vendors, the Company believes its
geological systems and software are Year 2000 compliant. In addition the Company
is performing other forms of due diligence to ensure that its geological systems
are compliant. The Company has not identified any non-information technology
systems that use embedded technology on which it relies and which it believes to
have a Year 2000 problem. However, the Company's assessment of these systems is
expected to continue through September 30, 1999.
The Company is also in the process of evaluating the risk presented by
potential Year 2000 non-compliance by third parties. Because such risks vary
substantially, companies are being contacted based on the estimated magnitude of
risk posed to the Company by their Year 2000 non-compliance. The Company
17
<PAGE>
anticipates that these efforts will continue through 1999 and will not result in
significant costs to the Company.
The Company believes that its most reasonable likely worst-cast Year
2000 scenario would be the shut-down of its purchaser pipelines. Should this
occur the Company would be required to transport its natural gas through
pipelines of other purchasers that are Year 2000 compliant or shut in
production volumes from being produced. Should this occur prouction and
associated cash flows may be impacted.
The Company's assessment of its Year 2000 issues involves many
assumptions. There can be no assurance that the Company's assumptions will prove
accurate, and actual results could differ significantly from the assumptions. In
conducting its Year 2000 compliance efforts, the Company has relied primarily on
vendor representations with respect to internal computerized systems and
representations from third parties with which the Company has business
relationships and has not independently verified representations. There can be
no assurance that these representations will prove accurate. A Year 2000 failure
could result in a business interruption that adversely affects the Company's
business, financial condition or results of operations. Although it is not
currently aware of any likely business disruptions, the Company is developing a
contingency plan to address and assess the readiness of its material suppliers,
customers and other entities as it relates to Year 2000 processing issues and
expects this work to be completed on or before September 30, 1999. The Company
is not insured for this type of a loss should a loss occur.
Accounting Pronouncements
Derivatives - In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 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 137"). SFAS 137 delays the
effective date for implementation of SFAS 133 for one year making SFAS 133
effective for all fiscal quarters of all fiscal years beginning after June 15,
2000. Retroactive application to periods prior to adoption is not allowed. The
Company has not quantified the impact of adoption on its financial statements or
the date it intends to adopt. Earlier application of SFAS 133 is encouraged, but
not prior to the beginning of any fiscal quarter that begins after issuance of
the statement.
FORWARD LOOKING STATEMENTS
The statements contained in all parts of this document, including, but
not limited to, those relating to the Company's drilling plans, its 3-D project
portfolio, capital expenditures, use of Offering proceeds, future capabilities,
the sufficiency of capital resources and liquidity to support working capital
and capital expenditure requirements, reinvestment of cash flows 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 the Company's dependence on its
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, the Company's dependence on its key personnel, the
Company's reliance on technological development and possible obsolescence of the
technology currently used by the Company, significant capital requirements of
the Company's exploration and development and technology development programs,
the potential impact of government regulations, litigation and environmental
matters, the Company's ability to manage its growth and achieve its business
strategy, competition, the uncertainty of reserve information and future net
18
<PAGE>
revenue estimates, property acquisition risks and other factors detailed in the
Company's 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.
19
<PAGE>
PART II - OTHER INFORMATION
Item 1 - Legal Proceedings............................................... None
Item 2 - Changes in Securities and Use of Proceeds......................
On May 6, 1999 the Company issued 1,400,000 shares of Common Stock and
420,000 warrants (the "Warrants"), each warrant entitling the holder to purchase
one share of Common Stock. The sale consisted of units of one share of common
stock and 0.3 warrants, each unit priced at $5.4375. The total price paid for
these securities was $7,612,000 before fees and expenses.
The purchasers of securities were as follows: Mark G. Egan; The Private
Investment Fund; Special Situations Private Equity Fund, L.P.; Special
Situations Fund III, L.P.; Special Situations Cayman Fund, L.P.; and an IRA for
John W. Elias.
The sale of the shares of Common Stock and Warrants were exempt from
registration requirements of the Securities Act of 1933, as amended, by virtue
of section 4(2) thereof as a transaction not involving any public offering.
Each Warrant is exercisable for the purchase of one share of Common Stock
upon a price of $5.35 per share. Each Warrant is exercisable through May 6,
2004. The Company may redeem a Warrant at a redemption price of $0.01 per
Warrant, at any time after any date at which the average daily per share closing
price for the immediately preceding 20 consecutive trading days on the Nasdaq
National Market exceeds $10.70.
The Warrants contain a provision to protect the Warrantholders against
dilution by adjusting the price at which the Warrants are exercisable and the
number of shares issuable upon exercise of the Warrants, upon the occurrence of
certain events. These events include: the payment of stock dividends, and
distributions, stock splits, and reclassifications.
The Company was required to (1) file a registration statement with the SEC
registering the resale of Common Stock, the Warrants and Common Stock underlying
the Warrants under the Securities Act of 1933 as amended, and (2) agree to
idemnify the purchasers of the securities in the August 12, 1999 private
placement from certain liabilities.
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 11, 1999.
(B) Set fourth below are the results of the voting with respect to each matter
acted upon at
Broker
For Against Withheld Abstain Non Votes
Election of Directors:
Vincent S. Andrew 4,845,593 22,814
David D. Benedict 4,845,593 22,814
Nils P. Peterson 4,845,593 22,914
Approval of the Appointment
of Deloitte and Touche LLP
as Independent Public
Accountants 4,913,353 36,682
In addition to the election of the directors indicated above, the term of
the of the following directors continued as directors following the meeting:
John W. Elias, James D. Calaway, Stanley Raphael, Robert W. Shower, William H.
White, and John Sfondrini.
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
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 3.2 to the Company's Registration Statement on Form
S-4 (Registration No. 333-17269)).
+4.1 -- Common Stock Subscription Agreement dated as of
April 30, 1999 between the Company and the purchasers named
therein (Incorporated by reference from exibit 4.5 to the
Company's form 10-Q/A for the quarter ended March 31, 1999).
+4.2 -- Warrant agreement dated as of May 6, 1999 between
the Company and the Warrant holders named therein (Included
in and incorporated by reference from exibit 4.5 to the
Company's Form 10-Q/A for the quarter ended March 31, 1999).
+4.3 -- Form of Warrant for the purchase of the Common Stock
(Included in and incorporated by reference from the Common
Stock Subscription Agreement from exibit 4.5 to the Company's
Form 10Q/A for the quarter ended March 31, 1999).
11.1 -- Computation of Earnings Per Share.
27.1 -- Financial Data Schedule.
+ Incorporated by reference as indicated.
(B) Reports on Form 8-K................................... None
22
<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 8/16/99 /S/ John W. Elias
- ----------------------- ------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board
Date 8/16/99 /S/ James D. Calaway
- ----------------------- ------------------------------
James D. Calaway
President and Chief Operations Officer
and Director
Date 8/16/99 /S/ Michael G. Long
- ----------------------- ------------------------------
Michael G. Long
Senior Vice President and
Chief Financial Officer
Date 8/16/99 /S/ Brian C. Baumler
- ----------------------- ------------------------------
Brian C. Baumler
Controller and Treasurer
23
<PAGE>
<TABLE>
EXHIBIT - 11.1
EDGE PETROLEUM CORPORATION
COMPUTATION OF EARNINGS PER SHARE
- -----------------------------------------------------------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
--------------- ---------------- --------------- ----------------
1999 1998 1999 1998
<S> <C> <C> <C> <C>
Basic common and common equivalent shares outstanding,
beginning of period 7,510,283 7,510,281 7,510,283 7,510,281
Weighted average shares and equivalent shares outstanding:
Issued in connection with the private offering 830,769 417,680
Restricted stock 248,260 261,430 248,260 261,277
------- ------- ------- -------
Basic weighted average common and common equivalent
shares outstanding, end of period 8,589,312 7,771,711 8,176,223 7,771,558
========= ========= ========= =========
Dilutive common stock options 32,454 31,835
--------- --------- --------- ---------
Diluted weighted average common and common equivalent
shares outstanding 8,589,312 7,804,165 8,176,223 7,803,393
========= ========= ========= =========
Net income (loss) before cumulative effect of accounting change $ (239,953) $ 46,822 $ (545,441) $ 665,602
Cumulative effect of accounting change 1,780,835
----------- -------- ---------- -----------
Net income (loss) $ (239,953) $ 46,822 $ (545,441) $ 2,446,437
========== ======== ========== ===========
BASIC EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of accounting change $ (0.03) $ 0.01 $ (0.07) $ 0.08
Cumulative effect of accounting change 0.23
-------- ------ ------- ------
Basic earnings (loss) per share $ (0.03) $ 0.01 $ (0.07) $ 0.31
======== ====== ======= ======
DILUTED EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of accounting change $ (0.03) $ 0.01 $ (0.07) $ 0.08
Cumulative effect of accounting change 0.23
-------- ------ ------- ------
Diluted earnings (loss) per share $ (0.03) $ 0.01 $ (0.07) $ 0.31
======= ====== ======= ======
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> Dec-31-1999
<PERIOD-START> Jan-01-1999
<PERIOD-END> Jun-30-1999
<CASH> 436,110
<SECURITIES> 0
<RECEIVABLES> 4,139,940
<ALLOWANCES> 250,000
<INVENTORY> 0
<CURRENT-ASSETS> 4,574,318
<PP&E> 78,939,290
<DEPRECIATION> 32,154,746
<TOTAL-ASSETS> 55,233,883
<CURRENT-LIABILITIES> 7,272,566
<BONDS> 7,150,000
0
0
<COMMON> 91,586
<OTHER-SE> 43,869,731
<TOTAL-LIABILITY-AND-EQUITY> 55,233,883
<SALES> 7,731,637
<TOTAL-REVENUES> 7,731,637
<CGS> 0
<TOTAL-COSTS> 8,234,603
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (545,441)
<INCOME-TAX> 0
<INCOME-CONTINUING> (545,411)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (545,441)
<EPS-BASIC> (0.07)
<EPS-DILUTED> (0.07)
</TABLE>
