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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO 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.)
Travis Tower
1301 Travis, Suite 2000
Houston, Texas 77002
(Address of principal executive offices)
(Zip code)
(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 by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [x]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Class Outstanding at May 11, 2004
----- ---------------------------
Common Stock 12,949,984
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2004 2003
------------- -------------
(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,465,727 $ 1,327,081
Accounts receivable, trade, net of allowance of $525,248 at March 31, 2004
and December 31, 2003 9,934,930 8,889,734
Accounts receivable, joint interest owners, net of allowance of $82,000 at
March 31, 2004 and December 31, 2003 1,202,232 1,797,877
Deferred tax asset 1,437,871 1,138,492
Derivative financial instruments -- 120,801
Other current assets 1,487,218 1,186,987
------------- -------------
Total current assets 16,527,978 14,460,972
PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and
natural gas properties (including unevaluated costs of $6.7 million and $5.0
million at March 31, 2004 and December 31, 2003, respectively) 104,072,584 97,980,757
DEFERRED TAX ASSET 4,035,856 5,570,137
OTHER ASSETS 325,993 --
------------- -------------
TOTAL ASSETS $ 124,962,411 $ 118,011,866
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 1,607,739 $ 1,732,935
Accrued liabilities 13,208,336 11,456,036
Accrued interest 45,195 --
Asset retirement obligation 391,982 323,513
Derivative financial instruments 728,024 --
------------- -------------
Total current liabilities 15,981,276 13,512,484
ASSET RETIREMENT OBLIGATION 1,448,962 1,488,482
LONG-TERM DEBT 20,000,000 21,000,000
------------- -------------
Total liabilities 37,430,238 36,000,966
------------- -------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares authorized; none issued and
outstanding -- --
Common stock, $0.01 par value; 25,000,000 shares authorized; 12,876,538 and
12,581,032 shares issued and outstanding at March 31, 2004 and December 31,
2003, respectively 128,765 125,810
Additional paid-in capital 78,084,701 75,282,007
Retained earnings 10,249,793 6,966,557
Accumulated other comprehensive loss (931,086) (363,474)
------------- -------------
Total stockholders' equity 87,532,173 82,010,900
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 124,962,411 $ 118,011,866
============= =============
See accompanying notes to consolidated financial statements.
1
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
Three Months Ended
March 31,
------------------------------
2004 2003
------------ ------------
OIL AND NATURAL GAS REVENUE $ 15,814,657 $ 6,838,770
OPERATING EXPENSES:
Lifting costs 1,205,073 594,804
Severance and ad valorem taxes 1,044,714 519,155
Depletion, depreciation, amortization and accretion 5,242,416 2,747,873
General and administrative expenses:
Deferred compensation - repriced options 1,111,099 --
Deferred compensation - restricted stock 96,500 86,664
Other general and administrative 1,900,827 1,256,262
------------ ------------
Total operating expenses 10,600,629 5,204,758
------------ ------------
OPERATING INCOME 5,214,028 1,634,012
OTHER INCOME AND EXPENSE:
Interest income 4,008 2,123
Interest expense, net of amounts capitalized (114,278) (176,389)
Amortization of deferred loan costs (29,636) --
------------ ------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 5,074,122 1,459,746
INCOME TAX EXPENSE (1,790,886) (521,722)
------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 3,283,236 938,024
CUMULATIVE EFFECT OF ACCOUNTING CHANGE -- (357,825)
------------ ------------
NET INCOME 3,283,236 580,199
OTHER COMPREHENSIVE INCOME:
Change in fair value of hedging instruments (567,612) (569,556)
------------ ------------
Other comprehensive income (loss) (567,612) (569,556)
------------ ------------
COMPREHENSIVE INCOME $ 2,715,624 $ 10,643
============ ============
BASIC EARNINGS PER SHARE:
Income before cumulative effect of accounting change $ 0.26 $ 0.10
Cumulative effect of accounting change -- (0.04)
------------ ------------
Basic earnings per share $ 0.26 $ 0.06
============ ============
DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting change $ 0.25 $ 0.10
Cumulative effect of accounting change -- (0.04)
------------ ------------
Diluted earnings per share $ 0.25 $ 0.06
============ ============
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 12,725,951 9,439,858
============ ============
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 13,317,839 9,583,303
============ ============
See accompanying notes to consolidated financial statements.
2
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31,
-----------------------------
2004 2003
------------ -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,283,236 $ 580,199
Adjustments to reconcile net income to net cash provided by (used in) operating
activities:
Cumulative effect of accounting change -- 357,825
Gain on the fair value of derivative (45,466) --
Deferred income taxes 1,790,886 521,722
Depletion, depreciation, amortization and accretion 5,242,416 2,747,873
Amortization of deferred loan costs 29,636 --
Deferred compensation 1,207,599 86,664
Changes in assets and liabilities:
Increase in accounts receivable, trade (1,017,896) (3,972,554)
(Increase) decrease in accounts receivable, joint interest owners 595,645 (42,713)
Increase in other assets (300,231) (235,464)
Decrease in accounts payable, trade (125,196) (874,912)
Increase in accrued liabilities 1,769,875 153,599
Increase in accrued interest payable 45,195 39,946
------------ -----------
Net cash provided by (used in) operating activities 12,475,699 (637,815)
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property and equipment additions (11,345,294) (3,097,324)
Proceeds from the sale of oil and natural gas properties 40,000 55,096
------------ -----------
Net cash used in investing activities (11,305,294) (3,042,228)
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from long-term debt -- 1,700,000
Payments of long-term debt (1,000,000) --
Net proceeds from issuance of common stock 1,323,870 --
Deferred loan costs (355,629) --
------------ -----------
Net cash provided by (used in) financing activities (31,759) 1,700,000
------------ -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1,138,646 (1,980,043)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 1,327,081 2,568,176
------------ -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 2,465,727 $ 588,133
============ ===========
See accompanying notes to consolidated financial statements.
3
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)
Accumulated
Common Stock Additional Other Total
-------------------- Paid-in Retained Comprehensive Stockholders'
Shares Amount Capital Earnings Loss Equity
------ ------ ------- -------- ---- ------
BALANCE,
DECEMBER 31, 2003 12,581,032 $125,810 $75,282,007 $ 6,966,557 $(363,474) $ 82,010,900
Issuance of common
stock 295,506 2,955 1,338,490 -- -- 1,341,445
Deferred
compensation -
restricted stock -- -- 96,500 -- -- 96,500
Deferred
compensation -
repriced options -- -- 1,111,099 -- -- 1,111,099
Change in valuation
of hedging
instruments -- -- -- -- (567,612) (567,612)
Tax benefit
associated with
exercise of
non-qualified
stock options -- -- 256,605 -- -- 256,605
Net income -- -- -- 3,283,236 -- 3,283,236
---------- -------- ----------- ----------- ---------- ------------
BALANCE,
March 31, 2004 12,876,538 $128,765 $78,084,701 $10,249,793 $(931,086) $ 87,532,173
========== ======== =========== =========== ========== ============
See accompanying notes to consolidated financial statements.
4
EDGE PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements included herein have been prepared by Edge
Petroleum Corporation, a Delaware corporation ("we", "our", "us" or the
"Company"), without audit pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC"), 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, 2003.
OIL AND NATURAL GAS PROPERTIES - Investments in oil and natural gas
properties are accounted for using the full cost method of accounting. All costs
associated with the exploration, development and acquisition of oil and natural
gas properties, including salaries, benefits and other internal costs directly
attributable to these activities are capitalized within a cost center. The
Company's oil and natural gas properties are located within the United States of
America and constitute one cost center.
In accordance with the full cost method of accounting, the Company
capitalizes a portion of interest expense on borrowed funds. Employee related
costs that are directly attributable to exploration and development activities
are also capitalized. These costs are considered to be direct costs based on the
nature of their function as it relates to the exploration and development
function.
Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Oil and natural gas properties
include costs of $6.7 million and $5.0 million at March 31, 2004 and December
31, 2003, respectively, related to unevaluated property, which were excluded
from capitalized costs being amortized. Unevaluated properties are evaluated
periodically for impairment on a property-by-property basis. If the results of
an assessment indicate that an unproved property is impaired, the amount of
impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development and
dismantlement costs, and restoration and abandonment costs, net of estimated
salvage values.
In addition, the capitalized costs of oil and natural gas properties are
subject to a "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of accumulated 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
expense. 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 SEC. In accordance with Staff Accounting Bulletin ("SAB")
No.103, "Update of Codification of Staff Accounting Bulletins," derivative
instruments qualifying as cash flow hedges are included in the computation of
limitation on capitalized costs. The period end price was within the collars
established by the Company's hedges at March 31, 2004 and thus did not affect
prices used in this calculation. No impairment related to the ceiling test was
required during the three-month periods ended March 31, 2004 or 2003.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the use of the purchase
method of accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite
5
lived intangible assets and initiates an annual review of impairment. The new
standard also requires that, at a minimum, all intangible assets be aggregated
and presented as a separate line item in the balance sheet.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, the Company has included the costs of mineral rights
associated with extracting oil and gas as a component of oil and gas properties.
If it is ultimately determined that SFAS No. 141 requires oil and gas companies
to classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, the Company would be
required to reclassify approximately $24.0 million and $22.8 million at March
31, 2004 and December 31, 2003, respectively, out of oil and gas properties and
into a separate intangible assets line item. These costs include those to
acquire contract based drilling and mineral use rights such as delay rentals,
lease bonuses, commissions and brokerage fees, and other leasehold costs. The
Company's cash flows and results of operations would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in
accordance with full cost accounting rules, as allowed by SFAS No. 142. Further,
the Company does not believe the classification of the costs of mineral rights
associated with extracting oil and gas as intangible assets would have any
impact on the Company's compliance with covenants under its debt agreements.
This issue was on the Emerging Issues Task Force ("EITF") agenda as Issue
04-2, "Whether Mineral Rights are Tangible or Intangible Assets and Related
Issues." At the March 2004 meeting the EITF reached a consensus that mineral
rights for mining companies should be accounted for as tangible assets. However,
the consensus does not address this topic as it relates to oil and natural gas
leaseholds. In April 2004, the FASB issued FASB Staff Position ("FSP") FAS 141-1
and FAS 142-1, "Interaction of FASB Statements No. 141, Business Combinations,
and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2,
"Whether Mineral Rights Are Tangible or Intangible Assets," which amends SFAS
No. 141 and 142 to exclude mineral use rights from the intangible category. It
is effective for the first reporting period beginning after April 29, 2004. Edge
will continue to monitor this issue and continue to classify oil and natural gas
leaseholds as oil and natural gas properties until further guidance is provided.
Sales of proved and unproved properties are accounted for as adjustments
of capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves.
ASSET RETIREMENT OBLIGATIONS - The Company records a liability for legal
obligations associated with the retirement of tangible long-lived assets in the
period in which they are incurred in accordance with Statement of Financial
Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations". The Company adopted this policy effective January 1, 2003, using a
cumulative effect approach to recognize transition amounts for asset retirement
obligations, asset retirement costs and accumulated accretion and depletion.
Under this method, when liabilities for dismantlement and abandonment costs,
excluding salvage values, are initially recorded, the carrying amount of the
related oil and gas properties are increased. Accretion of the liability is
recognized each period using the interest method of allocation, and the
capitalized cost is depleted over the useful life of the related asset.
At January 1, 2003, the Company recorded the present value of its future
Asset Retirement Obligations ("ARO") for oil and natural gas properties and
related equipment. The cumulative effect of the adoption of SFAS No. 143 and the
change in accounting principle was a charge to net income during the first
quarter of 2003 of $357,825, net of taxes of $192,675. The changes to the ARO
during the periods ended March 31, 2004 and 2003 are as follows:
Three Months Ended March 31,
----------------------------
2004 2003
----------- --------
ARO, Beginning of Period $ 1,811,995 $942,736
Liabilities incurred in the current period 86,311 17,951
6
Liabilities settled in the current period (83,647) --
Accretion expense 26,285 15,088
----------- --------
ARO, End of Period $ 1,840,944 $975,775
=========== ========
ARO liabilities incurred during the three months ended March 31, 2004
include obligations for nine new wells drilled during the quarter. Liabilities
settled during the quarter ended March 31, 2004 included three wells that were
plugged and one well that was sold.
STOCK-BASED COMPENSATION - The Company accounts for stock compensation
plans under the intrinsic value method of Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation
expense is recognized for stock options that had an exercise price equal to or
greater than the market value of the underlying common stock on the date of
grant. As allowed by SFAS No. 123, "Accounting for Stock-Based Compensation,"
the Company has continued to apply APB Opinion No. 25 for purposes of
determining net income. In December 2002, the FASB issued SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
amendment of FASB Statement No. 123" to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Additionally, the statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based compensation and the effect of the method used on reported results.
Had compensation expense for stock-based compensation been determined
based on the fair value at the date of grant, the Company's net income and
earnings per share would have been as follows:
Three Months Ended
March 31,
------------------------------
2004 2003
------------- -------------
Net income as reported $ 3,283,236 $ 580,199
Add:
Stock based employee compensation expense included in reported net
income, net of related income tax 718,942 --
Deduct:
Total stock based employee compensation expense determined under fair
value based method for all awards, net of related income tax (55,201) (66,075)
------------- -------------
Pro forma net income $ 3,946,977 $ 514,124
============= =============
Earnings Per Share:
Basic - as reported $ 0.26 $ 0.06
Basic - pro forma $ 0.31 $ 0.05
Diluted - as reported $ 0.25 $ 0.06
Diluted - pro forma $ 0.30 $ 0.05
The Company is also subject to reporting requirements of FASB
Interpretation No. ("FIN") 44, "Accounting for Certain Transactions involving
Stock Compensation" that requires a non-cash charge to deferred compensation
expense if the market price of the Company's common stock at the end of a
reporting period is greater than the exercise price of certain stock options.
After the first such adjustment is made, each subsequent period is adjusted
upward or downward to the extent that the market price exceeds the exercise
price of the options. The charge is related to non-qualified stock options
granted to employees and directors in prior years and re-priced in May 1999, as
well as certain options newly issued in conjunction with the repricing. A charge
of $1.1 million was required for the three months ended March 31, 2004. No
charge related to FIN 44 was required during the three-month period ended March
31, 2003.
7
ACCOUNTING PRONOUNCEMENTS - In December 2003, the FASB issued revised
Interpretation No. 46 ("FIN 46R"), "Consolidation of Variable Interest Entities,
an Interpretation of ARB No. 51". FIN 46R requires a company to consolidate a
variable interest entity, as defined, when the company will absorb a majority of
the variable interest entity's expected losses, receive a majority of the
variable interest entity's expected residual returns, or both. FIN 46R also
requires certain disclosures relating to consolidated variable interest entities
and unconsolidated variable interest entities in which a company has a
significant variable interest. The provisions of FIN 46R are required for
companies that have interests in variable interest entities or potential
variable interest entities commonly referred to as special-purpose entities for
periods ending after December 15, 2003. The provisions of FIN 46R are required
to be applied for periods ending after March 15, 2004 for all other types of
entities. The Company shares interests with related parties in a variety of
different partnership and joint venture entities in order to share the rewards
of ownership in certain oil and natural gas royalties. The Company does not
provide supplemental support to these entities nor does it own voting rights. In
general, these entities are structured such that the voting and sharing ratios
in these entities are consistent with the allocation of the entities'
distributions of cash from royalty revenues. The Company is not impacted by FIN
46R because the Company will not absorb a majority of the expected losses or
receive a majority of the expected residual returns, as defined by FIN 46R, and
accordingly the Company is not required to consolidate these interests.
2. LONG TERM DEBT
Effective December 31, 2003, the Company entered into a new amended and
restated credit facility (the "Credit Facility") which permits borrowings up to
the lesser of (i) the borrowing base or (ii) $100 million. Borrowings under the
Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus
2.25%. As of March 31, 2004, $20.0 million in borrowings were outstanding under
the Credit Facility. The Credit Facility matures December 31, 2006 and is
secured by substantially all of the Company's assets.
Effective December 31, 2003, the borrowing base under the Credit Facility
was increased to $40.0 million; primarily as a result of the acquisition of
properties in the Miller merger and our drilling activities since the last
redetermination. At March 31, 2004, the Company's available borrowing capacity
under this facility was $20.0 million.
The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings, 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) consolidated EBITDA (defined as EBITDA less similar non-cash
items and exploration and abandonment expenses for such period) of the Company
for the four fiscal quarters then ended to (b) the consolidated interest expense
of the Company for the four fiscal quarters then ended, not be less than 3.5 to
1.0. The Working Capital ratio requires that the amount of the Company's
consolidated current assets less its consolidated current liabilities, as
defined in the agreement, be at least $1.0 million. The Maximum Leverage ratio
requires that the ratio, as of the last day of any fiscal quarter, of (a) Total
Indebtedness (as defined in the Credit Facility) as of such fiscal quarter to
(b) an amount equal to consolidated EBITDAX for the two quarters then ended
times two, shall not be greater than 3.0 to 1.0 At March 31, 2004, the Company
was in compliance with the above-mentioned covenants. EBITDA and EBITDAX were
part of a negotiated covenant with our lender and are presented here as
disclosure of our compliance with that covenant.
3. EARNINGS PER SHARE
The Company accounts 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
8
earnings per common share assumes the exercise of all stock options and warrants
having exercise prices less than the average market price of the common stock
during the periods, using the treasury stock method.
The following is a reconciliation of the numerators and denominators of
basic and diluted earnings per common share computations, in accordance with
SFAS No. 128, for the three-month periods ended March 31, 2004 and 2003:
Three Months Ended March 31, 2004 Three Months Ended March 31, 2003
--------------------------------------- ---------------------------------------
Per
Income Shares Per Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- --------- ----------- ------------- --------
BASIC EPS
Income available to
common stockholders $3,283,236 12,725,951 $ 0.26 $580,199 9,439,858 $ 0.06
Effect of dilutive
securities:
Restricted stock -- 123,033 -- -- 95,976 --
Common stock options -- 468,855 (0.01) -- 47,469 --
---------- ----------- -------- --------- ----------- --------
DILUTED EPS
Income available to
common stockholders $3,283,236 13,317,839 $ 0.25 $580,199 9,583,303 $ 0.06
========== =========== ======== ========= =========== ========
4. INCOME TAXES
The Company accounts 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.
The Company currently estimates that its effective tax rate for the year
ending December 31, 2004 will be approximately 35.3%. A provision for income
taxes of $1.8 million and $0.5 million was reported for the three months ended
March 31, 2004 and 2003, respectively. The Company was not required to pay
income taxes in 2003 or 2002.
5. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
A summary of non-cash investing and financing activities for the three
months ended March 31, 2004 and 2003 is presented below:
Number of
shares Fair Market
Description issued Value
- ---------------------------------------------------------------- --------- -----------
THREE MONTHS ENDED MARCH 31, 2004:
Shares issued to satisfy restricted stock grants 56,136 $354,183
Shares issued to fund the Company's matching contribution under
the Company's 401 (k) plan 1,590 $ 17,575
THREE MONTHS ENDED MARCH 31, 2003:
Shares issued to satisfy restricted stock grants 46,330 $176,090
Shares issued to fund the Company's matching contribution under
the Company's 401 (k) plan 3,150 $ 12,750
9
The Company considers all highly liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents.
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
For the Three Months Ended
March 31,
--------------------------
2004 2003
------- ------
Cash paid during the period for:
Interest, net of amounts capitalized $69,083 $8,745
Interest paid for the three months ended March 31, 2004 and 2003 excludes
amounts capitalized of $88,555 and $75,923, respectively. The Company was not
required to pay income taxes in 2003 or 2002.
6. HEDGING ACTIVITIES
Due to the volatility of oil and natural gas prices, the Company
periodically enters into price risk management transactions (e.g., swaps,
collars and floors) for a portion of its 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 limits the Company's ability
to benefit from increases in the price of oil and natural gas, it also reduces
the Company's potential exposure to adverse price movements. The Company's
hedging arrangements, to the extent it enters into any, apply to only a portion
of its production and provide only partial price protection against declines in
oil and natural gas prices and limits the Company's potential gains from future
increases in prices. The Company's management sets all of the Company's hedging
policies, including volumes, types of instruments and counterparties, on a
quarterly basis. These policies are implemented by management through the
execution of trades by the Chief Financial Officer after consultation and
concurrence by the President and Chairman of the Board. The Board of Directors
reviews the Company's hedge policies and trades. The Company accounts for most
of these transactions as hedging activities and, accordingly, realized gains and
losses are included in oil and natural gas revenue during the period the hedged
transactions occur.
The Company's gas hedges had no impact on revenues for the quarter ended
March 31, 2004. For the quarter ended March 31, 2003, the Company realized a
loss of $2.2 million.
The Company elected not to apply hedge accounting to its crude oil collar
entered into in March 2004. As a result, the change in the fair value for the
oil collar for the quarter ended March 31, 2004 of $45,466 is reflected in oil
and natural gas revenue for the three months ended March 31, 2004.
The outstanding hedges at March 31, 2004 and December 31, 2003 impacting
the balance sheet were as follows:
Unrealized Hedging Gains
(Losses)
As of
--------------------------
Transaction Transaction Price Volumes March 31, December 31,
Date Type Beginning Ending Per Unit Per Day 2004 2003
- ------------- ----------- --------- -------- ----------- ------- --------- ------------
NATURAL GAS:
12/03 Natural
Gas
Collar (1) 1/1/04 3/31/04 $4.50-$7.05 5,000 $ -- $37,688
08/03 Natural
Gas
Collar (1)(2) 4/1/04 9/30/04 $4.50-$6.00 10,000 (510,609) 42,996
08/03 Natural
Gas 1/1/04 3/31/04
Collar (1)(2) 10/1/04 12/31/04 $4.50-$7.00 10,000 (157,999) 40,117
10
02/04 Natural
Gas $4.50-
Collar (1) 4/1/04 9/30/04 $6.20 5,000 (197,323) --
03/04 Natural
Gas $4.50-
Collar (1) 10/1/04 12/31/04 $7.25 5,000 92,441 --
10/02 Natural
Gas $4.00-
Collar 1/1/03 12/31/03 $4.25 10,000 -- --
CRUDE OIL:
03/04 Crude
Oil $30.00-
Collar (3) 4/1/04 12/31/04 $35.50 400 45,466 --
---------- ---------
$ (728,024) $ 120,801
========== =========
(1) The Company's current hedging activities for natural gas were
entered into on a per MMbtu delivered price basis, using the Houston
Ship Channel Index, with settlement for each calendar month
occurring five business days following the expiration date.
(2) This hedge was entered into at a cost of $686,250.
(3) Hedge accounting is not applied to the Company's collar on crude
oil, which was entered into on a per barrel delivered price basis,
using the West Texas Intermediate Index, with settlement for each
calendar month accruing five business days following the expiration
date. The change in fair value is reflected in net revenue for the
three months ended March 31, 2004.
7. MILLER EXPLORATION COMPANY MERGER
On December 4, 2003, Edge acquired 100% of the outstanding common stock of
Miller Exploration Company ("Miller") in a tax-free exchange pursuant to which
Miller became a wholly-owned subsidiary of Edge. The acquisition of Miller was
accounted for using the purchase method of accounting.
The following unaudited pro forma financial information has been prepared
to present the combined results of Edge and Miller for the three months ended
March 31, 2003, as if the merger had occurred at the beginning of the period
presented. This unaudited pro forma consolidated statement of operations data
does not include adjustments to reflect any cost savings or other operational
efficiencies that may be realized as a result of the merger of Edge and Miller,
or any future merger-related restructuring or integration expenses. The pro
forma data presented is based on numerous assumptions and is not necessarily
indicative of future results of operations of the merged companies.
Quarter Ended
March 31, 2003
----------------------
(In thousands, except
per share data)
STATEMENT OF OPERATIONS DATA
Revenues $ 10,205
Income before cumulative effect of accounting change $ 1,981
Basic earnings per share before cumulative effect of
accounting change $ 0.17
Diluted earnings per share before cumulative effect of
accounting change $ 0.16
8. COMMITMENTS AND CONTINGENCIES
From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. While the outcome of lawsuits cannot
be predicted with certainty, the Company is not currently a party to any
proceeding that it believes, if determined in a manner adverse to the Company,
could have a potential material adverse effect on its financial condition,
results of operations or cash flows.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is management's discussion and analysis of 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 Management's Discussion
and Analysis of Financial Condition and Results of Operations and our audited
consolidated financial statements included in our annual report on Form 10-K for
the year ended December 31, 2003.
FORWARD LOOKING STATEMENTS
The statements contained in all parts of this document, including, but not
limited to, those relating to our outlook, the effects of the merger with Miller
Exploration Company and our acquisition of properties in South Texas (including
any expectations regarding increases in our liquidity or available credit), our
ability to access the capital markets to raise additional capital, our drilling
plans, our 3-D project portfolio, capital expenditures, future capabilities, the
sufficiency of capital resources and liquidity to support working capital and
capital expenditure requirements, reinvestment of cash flows, use of NOLs, tax
rates, the outcome of litigation, and any other statements regarding future
operations, financial results, business plans, sources of liquidity and cash
needs and other statements that are not historical facts are forward looking
statements. When used in this document, the words "anticipate," "estimate,"
"expect," "may," "project," "believe," "budgeted," "intend," "plan,"
"potential," "forecast," "might," "predict," "should" 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 results of and our dependence on our
exploratory and development 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, the significant capital requirements of
our exploration and development and technology development programs, the
potential impact of government regulations and liability for environmental
matters, results of litigation, our ability to manage our growth and achieve our
business strategy, competition from larger oil and gas companies, 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. All subsequent written
and oral forward-looking statements attributable to the Company or the persons
acting on its behalf are expressly qualified in their entirety by the reference
to these risks and uncertainties.
GENERAL OVERVIEW
Edge Petroleum Corporation is a Houston-based independent energy company
that focuses its exploration, production and marketing activities in selected
onshore basins of the United States.
We were organized as a Delaware corporation in August 1996 in connection
with our initial public offering (the "Offering") and the related combination of
certain entities that held interests in the Edge Joint Venture II (the "Joint
Venture") and certain other oil and natural gas properties, herein referred to
as the "Combination". In a series of combination transactions, we issued an
aggregate of 4,701,361 shares of common stock and received in exchange 100% of
the ownership interests in the Joint Venture and certain other oil and natural
gas properties. In March 1997, and contemporaneously with the Combination, we
completed the Offering of 2,760,000 shares of our common stock generating
proceeds of approximately $40 million, net of expenses. We undertook a top-level
management change late in 1998 and began a shift in strategy from pure
exploration which focused more on prospect generation to our current strategy
which focuses on a balanced program of exploration, exploitation and development
and acquisition of oil and gas properties.
In December 2003, we acquired 100 percent of the outstanding stock of
Miller Exploration Company ("Miller"). The transaction was treated as a tax-free
reorganization and accounted for as a purchase business
12
combination. In the merger, we issued approximately 2.6 million shares of Edge
common stock using a ratio of 1.22342 Edge shares for each share of Miller
common stock outstanding. Miller continues to conduct exploration and
development activities as a wholly-owned subsidiary of Edge.
INDUSTRY AND ECONOMIC FACTORS
In managing our business, we must deal with many factors inherent in our
industry. First and foremost is the fluctuation of oil and gas prices.
Historically, oil and gas markets have been cyclical and volatile, with future
price movements difficult to predict. While our revenues are a function of both
production and prices, wide swings in commodity prices have most often had the
greatest impact on our results of operations.
Our operations entail significant complexities. Advanced technologies
requiring highly trained personnel are utilized in both exploration and
production. Even when the technology is properly used, we may still not know
conclusively if hydrocarbons will be present or the rate at which they will be
produced. Exploration is a high-risk activity, often times resulting in no
commercially productive reservoirs being discovered. Moreover, costs associated
with operating within our industry are substantial.
The oil and gas industry is highly competitive. We compete with major and
diversified energy companies, independent oil and gas businesses and individual
operators. In addition, the industry as a whole competes with other businesses
that supply energy to industrial and commercial end users.
Extensive federal, state and local regulation of the industry
significantly affects our operations. In particular, our activities are subject
to stringent environmental regulations. These regulations have increased the
costs of planning, designing, drilling, installing, operating and abandoning oil
and gas wells and related facilities. These regulations may become more
demanding in the future.
APPROACH TO THE BUSINESS
Profitable growth of our business will largely depend upon our ability to
successfully find and develop new proved reserves of oil and natural gas in a
cost effective manner. In order to achieve an overall acceptable rate of growth,
we maintain a blended portfolio of low, moderate and higher risk exploration and
development projects. We also attempt to make selected acquisitions of oil and
gas properties to augment our growth. We believe that this approach should allow
for consistent increases in our oil and gas reserves, while minimizing the
chance of failure. To further mitigate risk, we have chosen to seek geologic and
geographic diversification by operating in multiple basins. We periodically
hedge our exposure to volatile oil and gas prices on a portion of our production
to reduce price risk. As of March 31, 2004, we have entered into hedge contracts
covering approximately 55% and 60% of our expected 2004 natural gas and crude
oil production, respectively.
Implementation of our business approach relies on our ability to fund
ongoing exploration and development projects with cash flow provided by
operating activities and external sources of capital. In late 2003, we announced
plans for record capital expenditures of approximately $28 million for 2004.
Subsequently, we have announced plans to expand the 2004 capital budget to
approximately $39 million. We do not include acquisitions in our budgeted
capital expenditures. Based on current expectations for production volumes and
commodity prices, we expect to fund those capital expenditures from internally
generated cash from operating activities.
For the first quarter of 2004, Edge reported a 22% growth in production as
compared to the previous quarter and production growth of 104% over the same
period a year ago. Debt was reduced by $1.0 million in the first quarter of 2004
to $20.0 million at March 31, 2004. As of that date, our debt to total capital
ratio was approximately 19%, which we believe will leave us with the financial
flexibility to continue to execute our business strategies.
MERGER
On December 4, 2003 we completed our acquisition of Miller Exploration
Company ("Miller"). Miller was an independent oil and gas exploration and
production company with exploration efforts concentrated primarily
13
in the Mississippi Salt Basin of central Mississippi. We acquired Miller for the
development and exploitation projects in each of Miller's core areas, increased
financial flexibility, and expansion of our core areas.
Under the terms of the merger agreement, each share of issued and
outstanding common stock of Miller was converted into 1.22342 shares of Edge
common stock. We issued approximately 2.6 million shares of Edge common stock to
the shareholders of Miller in exchange for all of the outstanding common stock
of Miller. The merger was treated as a tax-free reorganization and accounted for
as a purchase business combination under generally accepted accounting
principles.
The fair value of assets acquired from Miller totaled $15.7 million and
included $6.4 million of cash. We incurred $1.2 million in costs associated with
the merger resulting in cash acquired in the merger of $5.2 million for the year
ended December 31, 2003. At March 31, 2004 we incurred approximately $203,000 of
expenses associated with the transaction.
The acquired Miller properties are estimated to contain at least 5.6 Bcfe
of proved reserves at December 31, 2003, of which approximately 60% was natural
gas and 100% was classified as proved developed. We operate the majority of the
acquired properties. Production from Miller properties for the period ended
March 31, 2004 was approximately 518,500 Mcfe. The acreage position was
approximately 83,800 gross (17,200 net) acres with an option to acquire 80,000
gross (68,000 net) acres at December 31, 2003.
OUTLOOK
We expect our drilling program to increase from 36 wells (17.922 net) in
2003 to approximately 45 to 50 wells (23.4 to 26.0 net) in 2004. Our expected
capital program will be approximately $39 million, 60% greater than 2003,
excluding acquisitions. Our expected added production volumes combined with a
strong commodity-pricing environment expected for the remainder of the year is
anticipated to produce record production volumes and cash flow. In order to
manage the anticipated growth over the coming year, we are planning to increase
our headcount resulting in increased G&A costs. However, we expect G&A costs to
fall on a unit of production basis. To help protect against the possibility that
commodity prices do not remain at the current levels, we have entered into
several hedges covering approximately 55% of our expected natural gas production
and 60% of our expected crude oil production streams for 2004 to offset the
negative impact of potential downward price movements. We also expect to spend
considerable effort in 2004 on acquisitions, as we seek to further our growth.
Our outlook and the expected results described above are both subject to
change based upon factors that include but are not limited to drilling results,
commodity prices, access to capital, the acquisitions market and factors
referred to in "Forward Looking Statements."
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues, expenses and disclosure of contingent assets and
liabilities in the accompanying financial statements. Changes in these estimates
could materially affect our financial position, results of operations or cash
flows. Key estimates used by management include revenue and expense accruals,
environmental costs, depreciation and amortization, asset impairment and fair
values of assets acquired. Significant accounting policies that we employ are
presented in the notes to the consolidated financial statements.
REVENUE RECOGNITION
We recognize oil and natural gas revenue from our interests in producing
wells as oil and natural gas is produced and sold from those wells. Oil and
natural gas sold by us is not significantly different from our share of
production.
OIL AND NATURAL GAS PROPERTIES
14
The accounting for our business is subject to special accounting rules
that are unique to the oil and gas industry. There are two allowable methods of
accounting for oil and gas business activities: the successful-efforts method
and the full-cost method. There are several significant differences between
these methods. Under the successful-efforts method, costs such as geological and
geophysical ("G&G"), exploratory dry holes and delay rentals are expensed as
incurred whereas under the full-cost method these types of charges would be
capitalized to their respective full-cost pool. In the measurement of impairment
of oil and gas properties, the successful-efforts method of accounting follows
the guidance provided in Statement of Financial Accounting Standards ("SFAS")
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," where
the first measurement for impairment is to compare the net book value of the
related asset to its undiscounted future cash flows using commodity prices
consistent with management expectations. Under the full-cost method, impairment
is determined by comparing the net book value (full-cost pool) to the future net
cash flows discounted at 10 percent using commodity prices in effect at the end
of the reporting period. Guidance to determine this impairment is provided in
SEC Regulation S-X Rule 4-10.
We have elected to use the full-cost method to account for our oil and gas
activities. Under this method, all costs associated with acquisition,
exploration and development of oil and gas reserves, including salaries,
benefits and other internal costs directly attributable to these activities are
capitalized within a cost center. Our oil and natural gas properties are located
within the United States of America, which constitutes one cost center. Although
some of these costs may ultimately result in no additional reserves, we expect
the benefits of successful wells to more than offset the costs of any
unsuccessful ones. As a result, we believe that the full-cost method of
accounting better reflects the true economics of exploring for and developing
oil and gas reserves. Our financial position and results of operations would
have been significantly different had we used the successful-efforts method of
accounting for our oil and gas investments.
Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Unproved properties are evaluated
periodically for impairment on a property-by-property basis. If the results of
an assessment indicate that an unproved property is impaired, the amount of
impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development and
dismantlement costs and restoration and abandonment costs, net of estimated
salvage value.
The capitalized costs of oil and natural gas properties are subject to a
"ceiling test," whereby to the extent that such 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 using hedge adjusted period end prices, 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 our quarterly
filings with the Securities and Exchange Commission. In accordance with Staff
Accounting Bulletin ("SAB") No.103, "Update of Codification of Staff Accounting
Bulletins," derivative instruments qualifying as cash flow hedges are included
in the computation of limitation on capitalized costs. The period end price was
within the collar established by the Company's hedges at March 31, 2004 and thus
did not affect prices used in this calculation. No adjustment related to the
ceiling test was required during the three months ended March 31, 2004 or 2003.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the use of the purchase
method of accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review of impairment. The new standard also requires that,
at a minimum, all intangible assets be aggregated and presented as a separate
line item in the balance sheet.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 141 requires
registrants to classify the costs of mineral rights associated with extracting
oil and gas as intangible assets in the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures. Historically, we have included the costs of mineral rights
associated with extracting oil and gas as a component of
15
oil and gas properties. If it is ultimately determined that SFAS No. 141
requires oil and gas companies to classify costs of mineral rights associated
with extracting oil and gas as a separate intangible assets line item on the
balance sheet, we would be required to reclassify approximately $24.0 million
and $22.8 million at March 31, 2004 and December 31, 2003, respectively, out of
oil and gas properties and into a separate intangible assets line item. These
costs include those to acquire contract based drilling and mineral use rights
such as delay rentals, lease bonuses, commissions and brokerage fees, and other
leasehold costs. Our cash flows and results of operations would not be affected
since such intangible assets would continue to be depleted and assessed for
impairment in accordance with full cost accounting rules, as allowed by SFAS No.
142. Further, we do not believe the classification of the costs of mineral
rights associated with extracting oil and gas as intangible assets would have
any impact on our compliance with covenants under our debt agreements.
This issue was on the Emerging Issues Task Force ("EITF") agenda as Issue
04-2, "Whether Mineral Rights are Tangible or Intangible Assets and Related
Issues." At the March 2004 meeting the EITF reached a consensus that mineral
rights for mining companies should be accounted for as tangible assets. However,
the consensus does not address this topic as it relates to oil and natural gas
leaseholds. In April 2004, the FASB issued FASB Staff Position ("FSP") FAS 141-1
and FAS 142-1, "Interaction of FASB Statements No. 141, Business Combinations,
and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2,
"Whether Mineral Rights Are Tangible or Intangible Assets," which amends SFAS
No. 141 and 142 to exclude mineral use rights from the intangible category. It
is effective for the first reporting period beginning after April 29, 2004. Edge
will continue to monitor this issue and continue to classify oil and natural gas
leaseholds as oil and natural gas properties until further guidance is provided.
Sales of proved and unproved properties are accounted for as adjustments
of capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves.
ASSET RETIREMENT OBLIGATIONS
We have certain obligations to remove tangible equipment and restore land
at the end of oil and gas production operations. Our removal and restoration
obligations are primarily associated with plugging and abandoning wells. Under
the full-cost method of accounting, as described in the preceding critical
accounting policy sections, the estimated discounted costs of the abandonment
obligations, net of salvage value, are currently included as a component of our
depletion base and expensed over the production life of the oil and gas
properties. Estimating the future asset removal costs is difficult and requires
management to make estimates and judgments because most of the removal
obligations are many years in the future and contracts and regulations often
have vague descriptions of what constitutes removal. Asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental,
safety and public relations considerations.
In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." We adopted this statement effective January 1, 2003, as discussed
in Note 1 to our Consolidated Financial Statements. SFAS No. 143 significantly
changed the method of accruing for costs an entity is legally obligated to incur
related to the retirement of fixed assets ("asset retirement obligations" or
"ARO"). Primarily, the new statement requires us to record a separate liability
for the discounted present value of our asset retirement obligations, with an
offsetting increase to the related oil and gas properties on the balance sheet.
Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas property
balance. In addition, increases in the discounted ARO liability resulting from
the passage of time will be reflected as accretion expense in the consolidated
statement of operations.
The adoption of SFAS No. 143 required a cumulative adjustment to reflect
the impact of implementing the statement had the rule been in effect since
inception. We, therefore, calculated the cumulative accretion expense on the ARO
liability and the cumulative depletion expense on the corresponding property
balance. The sum of these
16
cumulative expenses was compared to the depletion expense originally recorded.
Because the historically recorded depletion expense was lower than the
cumulative expense calculated under SFAS No. 143, the difference resulted in a
loss, which we recorded as cumulative effect of change in accounting principle
on January 1, 2003.
Going forward, our depletion expense will be reduced since we will deplete
a discounted amount of asset retirement costs rather than the undiscounted value
previously depleted. The lower depletion expense under SFAS No. 143 is offset,
however, by accretion expense, which reflects the increases in the discounted
asset retirement obligation liability over time.
OIL AND NATURAL GAS RESERVES
Our estimate of proved reserves is based on the quantities of oil and gas
which geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in the future years from known reservoirs under existing economic
and operating conditions. The accuracy of any reserve estimate is a function of
the quality of available data, engineering and geological interpretation, and
judgment. For example, we must estimate the amount and timing of future
operating costs, severance taxes, development costs, and workover costs, all of
which may in fact vary considerably from actual results. In addition, as prices
and cost levels change from year to year, the estimate of proved reserves also
changes. Any significant variance in these assumptions could materially affect
the estimated quantity and value of our reserves.
Despite the inherent imprecision in these engineering estimates, our
reserves are used throughout our financial statements. For example, since we use
the units-of-production method to amortize our oil and gas properties, the
quantity of reserves could significantly impact our depreciation, depletion, and
amortization expense ("DD&A") and accretion expense. Our oil and gas properties
are also subject to a "ceiling" limitation based in part on the quantity of our
proved reserves. Finally, these reserves are the basis for our supplemental oil
and gas disclosures.
We engage an independent petroleum engineering firm to prepare an
independent estimate of our proved hydrocarbon liquid and gas reserves.
INCOME TAXES
We record deferred tax assets and liabilities to account for the expected
future tax consequences of events that have been recognized in our financial
statements and our tax returns. We routinely assess the realizability of our
deferred tax assets. If we conclude that it is more likely than not that some
portion or all of the deferred tax assets will not be realized under accounting
standards, the tax asset would be reduced by a valuation allowance. We consider
future taxable income in making such assessments. Numerous judgments and
assumptions are inherent in the determination of future taxable income,
including factors such as future operating conditions (particularly as related
to prevailing oil and gas prices). The Company is not currently required to pay
any federal income taxes.
DERIVATIVES AND HEDGING ACTIVITIES
Our revenue, profitability and future rate of growth and ability to borrow
funds or obtain additional capital, and the carrying value of our properties,
are substantially dependent upon prevailing prices for oil and natural gas.
These prices are dependent upon numerous factors beyond our control, such as
economic, political and regulatory developments and competition from other
sources of energy. A substantial or extended decline in oil and natural gas
prices could have a material adverse effect on our financial condition, results
of operations and access to capital, as well as the quantities of oil and
natural gas reserves that we may economically produce.
Due to the instability of oil and natural gas prices, we may 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 commodity price
fluctuations. While the use of these arrangements limits our ability to benefit
from increases in the price of oil and natural gas, it also reduces our
potential exposure to 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
17
natural gas prices and limits our potential gains from future increases in
prices. Our management sets all of our hedging policies, including volumes,
types of instruments and counterparties, on a quarterly basis. These policies
are implemented by management through the execution of trades by the Chief
Financial Officer after consultation and concurrence by the President and
Chairman of the Board. Our Board of Directors reviews all hedging policies and
trades. We account for a majority of these transactions as hedging activities
and, accordingly, realized gains and losses are included in oil and natural gas
revenue during the period the hedged transactions occur. For transactions not
accounted for using hedge accounting, the change in the fair value is reflected
in oil and natural gas revenue immediately.
We formally assess, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are expected to be
highly effective in offsetting changes in cash flows of the hedged transactions.
In the event it is determined that the use of a particular derivative may not be
or has ceased to be effective in pursuing a hedging strategy, hedge accounting
is discontinued prospectively.
STOCK-BASED COMPENSATION
We account for stock compensation plans under the intrinsic value method
of Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock
Issued to Employees." No compensation expense is recognized for stock options
that had an exercise price equal to or greater than the market value of their
underlying common stock on the date of grant. As allowed by SFAS No. 123,
"Accounting for Stock Based Compensation," we have continued to apply APB
Opinion No. 25 for purposes of determining net income. In December 2002, the
FASB issued SFAS No. 148, "Accounting for Stock Based Compensation - -
Transition and Disclosure - - an amendment of FASB Statement No. 123" to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. We elected not to
change to the fair value method. Additionally, the statement amended the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based compensation and the effect of the method used on reported results.
We are also subject to reporting requirements of FASB Interpretation No.
("FIN") 44, "Accounting for Certain Transactions involving Stock Compensation"
that requires a non-cash charge to deferred compensation expense if the market
price of our common stock at the end of a reporting period is greater than the
exercise price of certain stock options. After the first such adjustment is
made, each subsequent period is adjusted upward or downward to the extent that
the market price exceeds the exercise price of the options. The charge is
related to non-qualified stock options granted to employees and directors in
prior years in conjunction with the repricing of those options.
RESULTS OF OPERATIONS
This section includes discussion of our first quarter 2004 and 2003
results of operations. We are an independent energy company engaged in the
exploration, development, acquisition and production of oil and natural gas. Our
resources and assets are managed and our results reported as one operating
segment. We conduct our operations primarily along the onshore United States,
Gulf Coast, with our primary emphasis in South Texas, Louisiana and Southeast
New Mexico.
REVENUE AND PRODUCTION
Oil and natural gas revenue increased 131% from $6.8 million in the first
quarter of 2003 to $15.8 million in the comparable 2004 period. For the three
months ended March 31, 2004, natural gas production comprised 77% of total
production and contributed 82% of total revenue, oil and condensate production
comprised 10% of total production and contributed 11% of total revenue, and
natural gas liquid (NGL) production comprised 13% of total production and
contributed 7% of total revenue. For the first quarter of 2003, natural gas
production comprised 74% of total production and contributed 77% of total
revenue, oil and condensate production comprised 11% of total production and
contributed 14% of total revenue, and NGL production comprised 15% of total
production and contributed 9% of total revenue.
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The following table summarizes volume and price information with respect
to our oil and gas production for the three-month periods ended March 31, 2004
and 2003:
2004 PERIOD COMPARED
TO 2003 PERIOD
-------------------------
MARCH 31, %
--------------------------- INCREASE INCREASE
2004 2003 (DECREASE) (DECREASE)
------------ ----------- ----------- ----------
PRODUCTION VOLUMES:
Natural gas (Mcf) 2,421,980 1,138,369 1,283,611 113%
Oil and condensate (Bbls) 53,828 28,974 24,854 86%
Natural gas liquids (Bbls) 69,485 39,198 30,287 77%
Natural gas equivalent (Mcfe) 3,161,858 1,547,401 1,614,457 104%
AVERAGE SALES PRICE:
Natural gas ($ per Mcf)(1) $ 5.35 $ 4.64 $ 0.71 15%
Oil and condensate ($ per Bbl)(1) $ 33.60 $ 33.73 $ (0.13) 0%
Natural gas liquids ($ per Bbl) $ 15.03 $ 14.91 $ 0.12 1%
Natural gas equivalent ($ per Mcfe) (1) $ 5.00 $ 4.42 $ 0.58 13%
OPERATING REVENUE:
Natural gas (1) $ 12,961,651 $ 5,277,220 $ 7,684,431 146%
Oil and condensate (1) 1,808,602 977,192 831,410 85%
Natural gas liquids 1,044,404 584,358 460,046 79%
------------ ----------- -----------
Total (1) $ 15,814,657 $ 6,838,770 $ 8,975,887 131%
============ =========== ===========
(1) Includes the effect of hedging and derivative transactions.
Our revenue is sensitive to changes in prices received for our products. A
substantial portion of our production is sold at prevailing market prices, which
fluctuate in response to many factors that are outside of our control.
Imbalances in the supply and demand for oil and natural gas can have a dramatic
effect on the prices we receive for our production. Political instability and
availability of alternative fuels could impact worldwide supply, while the
economy, weather and other factors outside of our control could impact demand.
Natural gas revenue increased 146% from $5.3 million for the three months
ended March 31, 2003 to $13.0 million for the same period in 2004 due to
significantly higher production and lower realized hedge losses. Average natural
gas production increased 113% from 12.6 MMcf/D in the three months ended March
31, 2003 to 26.6 MMcf/D in the comparable 2004 period due to production from new
wells drilled and acquired, primarily our O'Connor Ranch East, Gato Creek,
Encinitas and Miller properties, partially offset by natural declines at our
Austin Field and O'Connor Ranch properties. This increase in production compared
to the prior year period resulted in an increase in revenue of approximately
$8.4 million (based on 2003 comparable period pre-hedge prices). For the three
months ended March 31, 2004, no natural gas hedge losses were realized but we
recognized $27,300 of the premium paid for a hedge entered into in 2003 that
decreased the effective natural gas sales price by $0.01 per Mcf. Included
within natural gas revenue for the three months ended March 31, 2003 was $2.2
million representing realized losses from hedging activity. These losses
decreased the effective natural gas sales price by $1.94 per Mcf for the three
months ended March 31, 2003. Excluding the effect of hedges, the average natural
gas sales price for production in the first quarter of 2004 was $5.36 per Mcf
compared to $6.57 per Mcf for the same period in 2003. This decrease in average
price received resulted in decreased revenue of approximately $2.9 million
(based on current year production).
Revenue from the sale of oil and condensate totaled $1.8 million for the
three months ended March 31, 2004, an increase of 85% from the comparable prior
year period total of $1.0 million due to increased production. Production
volumes for oil and condensate increased 86% to 592 Bbls/D for the three months
ended March 31, 2004 compared to 322 Bbls/D for the same prior year period due
primarily to production from the properties acquired from Miller, as well as new
wells drilled. The increase in oil and condensate production resulted in an
increase in
19
revenue of approximately $838,200 (based on 2003 comparable period average
prices). The average realized price for oil and condensate for the three months
ended March 31, 2004 was $33.60 per barrel compared to $33.73 per barrel in the
same period of 2003. Lower average prices for the first quarter of 2004 resulted
in a decrease in revenue of approximately $6,800 (based on current year
production). Included in oil revenue for the three months ended March 31, 2004
was $45,500, or $0.84 per barrel, representing a mark to market gain on the fair
value of an oil derivative. We elected not to apply hedge accounting to this
transaction. See Note 6 to our Consolidated Financial Statements.
Revenue from the sale of NGLs totaled over $1.0 million for the three
months ended March 31, 2004, an increase of 79% from the 2003 first quarter
total of $0.6 million. Production volumes for NGLs increased 77%, from 436
Bbls/D for the three months ended March 31, 2003 to 764 Bbls/D for the three
months ended March 31, 2004 due primarily to increased production from new wells
drilled and acquired. The increase in NGL production increased revenue by
$451,500 (based on 2003 comparable period average prices). Higher average
realized prices for the three months ended March 31, 2004 resulted in an
increase in revenue of $8,500 (based on current year production). The average
realized price for NGLs for the three months ended March 31, 2004 was $15.03 per
barrel compared to $14.91 per barrel for the same period in 2003.
COSTS AND OPERATING EXPENSES
The table below presents a detail of our expenses for the three months
ended March 31, 2004 and 2003:
2004 PERIOD COMPARED
TO 2003 PERIOD
-------------------------
MARCH 31, %
--------------------------- INCREASE INCREASE
2004 2003 (DECREASE) (DECREASE)
------------ ----------- ----------- ----------
Lease operating costs $ 1,205,073 $ 594,804 $ 610,269 103%
Severance and other taxes 1,044,714 519,155 525,559 101%
Depreciation, depletion, amortization and
accretion:
Oil and gas property and equipment 5,129,154 2,503,001 2,626,153 105%
Other assets 86,977 229,784 (142,807) -62%
ARO accretion 26,285 15,088 11,197 74%
General and administrative:
Deferred compensation - - repriced
options 1,111,099 -- 1,111,099 100%
Deferred compensation - - restricted
stock 96,500 86,664 9,836 11%
Other general and administrative 1,900,827 1,256,262 644,565 51%
------------ ----------- -----------
10,600,629 5,204,758 5,395,871 104%
Other expense, net 139,906 174,266 (34,360) -20%
------------ ----------- -----------
Total $ 10,740,535 $ 5,379,024 $ 5,361,511 100%
============ =========== ===========
Lease operating expenses for the three months ended March 31, 2004 totaled
$1.2 million compared to $0.6 million in the same period of 2003, an increase of
103%. Current year results were impacted by the drilling of 38 wells since the
first quarter of 2003 as well as operations on properties newly acquired in late
2003, increased production of 104% over 2003, the Miller merger, and
acquisitions of properties from third parties. Operating expenses averaged $0.38
per Mcfe for the three months ended March 31, 2004, the same as in the
comparable prior year period.
Severance and ad valorem taxes for the three months ended March 31, 2004
increased from $0.5 million in the first quarter of 2003, to $1.0 million in
same period of 2004. Severance tax expense for the first quarter of 2004 of $0.9
million was 108% higher than the comparable prior year period as a result of
higher revenue. For the three months ended March 31, 2004, severance tax expense
was approximately 6.0% of revenue subject to severance
20
taxes compared to 5.0% of revenue subject to severance taxes for the comparable
2003 period. The increase in tax as a percent of revenue was due primarily to a
shift in our revenue stream to properties with higher severance tax rates. Ad
valorem costs increased 59% from $72,000 in the first quarter of 2003 to
$114,463 in the first quarter of 2004. On an equivalent basis, severance and ad
valorem taxes averaged $0.33 per Mcfe and $0.34 per Mcfe for the three months
ended March 31, 2004 and 2003, respectively.
Depletion, depreciation, and amortization ("DD&A") and accretion expense
for the three months ended March 31, 2004 totaled $5.2 million compared to $2.7
million for the three months ended March 31, 2003. Depletion on our oil and
natural gas properties totaled $5.1 million for the first quarter of 2004
compared to $2.5 million in the same period of 2003. Depletion expense on a unit
of production basis for the three months ended March 31, 2004 was $1.62 per
Mcfe, comparable to the 2003 first quarter rate. The increase in depletion
expense was entirely due to the higher production levels in the first quarter of
2004 as compared to the first quarter of 2003. Depreciation of furniture and
fixtures totaled $86,977, a decrease of 62% compared to the prior year first
quarter total of $229,784. In the first quarter of 2003, we moved offices
resulting in accelerated amortization of leasehold costs associated with our
prior office building lease. We adopted SFAS No. 143 effective January 1, 2003.
As a result, we recorded accretion expense associated with our asset retirement
obligation for the three months ended March 31, 2004 and 2003 of $26,285 and
$15,088, respectively.
Total G&A for the three months ended March 31, 2004 was $3.1 million, an
increase of 131% compared to the comparable prior year total of $1.3 million.
G&A costs include deferred compensation related to repriced options, deferred
compensation related to restricted stock grants and other G&A costs.
Deferred compensation expense consists of costs reported in accordance
with FIN 44 and amortization related to restricted stock awards. A FIN 44 charge
of $1.1 million was incurred for the three months ended March 31, 2004 compared
to no charge 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 than 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
based on the trading price of our common stock at the end of each such period.
We are required 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 newly issued options in conjunction with the
repricing.
Amortization related to restricted stock awards granted over the past
three years totaled $96,500 and $86,664, respectively, for the three months
ended March 31, 2004 and 2003.
Other G&A for the three months ended March 31, 2004, which does not
include the deferred compensation expenses discussed above, totaled $1.9
million, a 51% increase from the comparable 2003 period total of $1.3 million.
The increase in other G&A was attributable to higher salary and benefits as well
as higher professional fees. In addition, we incurred costs associated with the
Miller acquisition of $203,000. For the three months ended March 31, 2004 and
2003, overhead reimbursement fees reduced G&A costs by $46,477 and $28,690,
respectively. Capitalized G&A costs further reduced other G&A by $507,064 and
$302,829, respectively, for the three months ended March 31, 2004 and 2003.
Other G&A on a unit of production basis for the three months ended March 31,
2004 was $0.60 per Mcfe compared to $0.81 per Mcfe for the comparable 2003
period.
Included in other income (expense) was interest expense of $114,278 for
the three months ended March 31, 2004 compared to $176,389 in the same 2003
period. Interest expense, including facility fees, was $202,833 for the first
quarter of 2004 on weighted average debt of $20.9 million compared to interest
expense of $252,312 on weighted average debt of approximately $21.2 million for
the first quarter of 2003. Capitalized interest for the three months ended March
31, 2004 totaled $88,555 compared to $75,923 in the same prior year period. At
March 31, 2004, our unproved property balance was $6.7 million compared to $5.0
million at December 31, 2003 and $6.3 at March 31, 2003, resulting in the
slightly higher capitalized interest for the 2004 period. We also reported
deferred loan costs of $29,636 during the first quarter of 2004. We amended our
credit facility after the Miller merger resulting in loan costs of $355,629 that
will be amortized over a three-year period ending December 31, 2006.
21
An income tax provision was recorded for the three months ended March 31,
2004 and 2003 of $1.8 million and $0.5 million, respectively. As of December 31,
2003, approximately $50.1 million of net operating loss carryforwards had been
accumulated or acquired that begin to expire in 2012. Currently, we do not
anticipate making federal tax payments in 2004.
Upon adoption of SFAS No. 143 on January 1, 2003, we recorded a cumulative
effect of a change in accounting principal of $357,825 (net of income taxes of
$192,675) to recognize transition amounts for asset retirement obligations,
asset retirement costs and accumulated depletion.
For the three months ended March 31, 2004, we had net income of $3.3
million, or $0.26 basic earnings per share and $0.25 diluted earnings per share,
as compared to net income of $0.6 million, or $0.06 basic and diluted earnings
per share in the comparable 2003 period. Basic weighted average shares
outstanding increased from approximately 9.4 million for the three months ended
March 31, 2003 to 12.7 million in the comparable 2004 period. The increase in
shares outstanding was due primarily to the issuance of stock for the
acquisition of Miller in December 2003 as well as the exercise of options, the
exercise of warrants and the vesting and issuance of restricted stock during
2003 and the first quarter of 2004.
LIQUIDITY AND CAPITAL RESOURCES
In March 1997, we completed our initial public offering which provided us
with proceeds of approximately $40 million, net of expenses and on May 6, 1999,
we completed a "Private Offering" of 1,400,000 shares of common stock at a price
of $5.40 per share. We 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. Total proceeds, net of offering
costs, were approximately $7.4 million of which $4.9 million was used to repay
debt under our revolving credit facility in place at the time, with the
remainder being utilized to satisfy working capital requirements and to fund a
portion of our exploration program. Pursuant to the terms of the private
placement, we filed a registration statement with the Commission registering the
resale of the shares of Common Stock and the warrants sold in the private
placement, as well as the resale of any shares of Common Stock issued pursuant
to such warrants. During November and December of 2003, we issued 375,000 shares
of Common Stock in connection with the exercise of the warrants that resulted in
proceeds to us of approximately $2.0 million. As of December 31, 2003, 45,000 of
these warrants were outstanding. On March 2, 2004, Mr. Elias, our Chairman and
Chief Executive Officer, exercised the remaining warrants which resulted in our
issuance to him of 45,000 shares of common stock and net proceeds to us of
$240,750.
Our primary ongoing source of capital is the cash flow generated from our
operating activities supplemented by borrowings under our credit facility. Both
of these sources are directly impacted by the amount of our oil and gas
reserves, production volumes and the commodity prices we receive. Reserves and
production volumes are influenced, in part, by the amount of future capital
expenditures. In turn, capital expenditures are influenced by many factors
including drilling results, oil and gas prices, industry conditions, prices,
availability of goods and services and the extent to which oil and gas
properties are acquired.
Capital Resources
Our primary needs for cash are for exploration, development and
acquisition of oil and gas properties, and the repayment of principal and
interest on outstanding debt. We attempt to fund our exploration and development
activities primarily through internally generated cash flows and budget capital
expenditures based on projected cash flows. We routinely adjust capital
expenditures in response to changes in oil and natural gas prices, drilling and
acquisition costs, and cash flow. We typically have funded acquisitions from
borrowings under our credit facility and cash flow from operations. We have
historically utilized net cash provided by operating activities, debt and equity
as capital resources to obtain necessary funding for all of our cash needs.
We had cash and cash equivalents at March 31, 2004 of $2.5 million
consisting primarily of short-term money market investments, as compared to $1.3
million at December 31, 2003. Working capital was $0.5 million as of March 31,
2004, as compared to $0.9 million at December 31, 2003.
22
Net Cash Provided By Operating Activities
Cash flows provided by operating activities were $12.5 million for the
three months ended March 31, 2004 compared to cash flows used in operating
activities of $0.6 million for the three months ended 2003. The significant
increase in cash flows provided by operating activities for the three months
ended March 31, 2004 compared to 2003 was primarily due to higher oil and gas
production revenue partially offset by higher operating expense. Although
fluctuations in commodity prices have been the primary reason for our short-term
changes in cash flow from operating activities, increased production volumes
significantly impacted us in the past few quarters. In an effort to reduce the
volatility realized on commodity prices, we enter into derivative instruments.
The impact in the first quarter of 2004 was not significant due to relatively
stable market prices. Oil and gas production revenue increased with a 104%
increase in production and a 13% increase in the average price received for our
production.
Net cash generated from operating activities is a function of commodity
prices, which are inherently volatile and unpredictable, production volumes,
operating efficiency and capital spending. Our business, as with other
extractive industries, is a depleting one in which each gas equivalent produced
must be replaced or we, and a critical source of our future liquidity, will
shrink. Based on the year-end reserve life index, our overall decline is
approximately 13% per year. Less predictable than production declines from our
proved reserves is the impact of constantly changing oil and natural gas prices
on cash flows and, therefore capital budgets.
For these reasons, we only forecast, for internal use by management, an
annual cash flow. These annual forecasts are revised monthly and capital budgets
are reviewed by management and adjusted as warranted by market conditions.
Longer-term cash flow and capital spending projections are neither developed nor
used by management to operate our business.
In the event such capital resources are not available to us, our drilling
and other activities may be curtailed.
Net Cash Used In Investing Activities
We reinvest a substantial portion of our cash flows in our drilling,
acquisition, land and geophysical activities. As a result, we used $11.3 million
in investing activities during the first quarter of 2004. Capital expenditures
of $9.4 million were attributable to the drilling of 9 gross wells, all of which
were successful. Leasehold acquisitions, including seismic data and other
geological and geophysical expenditures totaled $1.7 million and acquisition
costs totaled $0.1 million for the three months ended March 31, 2004. The
remaining capital expenditures were associated with computer hardware and office
equipment. Proceeds from the sale of oil and gas properties totaled $40,000
during the first quarter of 2004. During the three months ended March 31, 2003,
we used $3.0 million in investing activities. Capital expenditures of $3.1
million for the three months ended March 31, 2003, were partially offset by
$55,096 in proceeds from the sale of oil and gas properties during the first
quarter of 2003.
We currently anticipate capital expenditures in 2004 to be approximately
$39.4 million. Approximately $31.4 million is allocated to our expected drilling
and production activities; $5.5 million is allocated to land and seismic
activities; and $2.5 million relates to capitalized interest and G&A and other.
We plan to fund these expenditures from expected cash flow from operations plus
some modest incremental borrowings. We have not explicitly budgeted for
acquisitions; however, we do expect to spend considerable effort evaluating
acquisition opportunities. We expect to fund acquisitions through traditional
reserve-based bank debt and/or the issuance of equity and, if required, through
additional debt and equity financings. We currently have $20.0 million of unused
borrowing capacity under our credit facility.
Net Cash Provided By Financing Activities
Cash flows used in financing activities totaled $31,759 for the three
months ended March 31, 2004. Repayments of $1.0 million under our current credit
facility as well as deferred loan costs of $355,629 associated with amending
that facility after the Miller merger were partially offset by $1.3 million in
proceeds from the issuance of common stock related to options and warrants
exercised in the first quarter of 2004. Cash flows provided by financing
activities totaled $1.7 million for the three months ended March 31, 2003, all
borrowings under our credit facility.
23
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 our 2004 capital expenditures,
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2004 cash
flows from operations are estimated to be sufficient to fund our budgeted
exploration and development program. We believe we will be able to generate
capital resources and liquidity sufficient to fund our capital expenditures and
meet such financial obligations as they come due.
CREDIT FACILITY
In March 2004, but effective December 31, 2003, the Company entered into a
new amended and restated credit facility (the "Credit Facility") which permits
borrowings up to the lesser of (i) the borrowing base or (ii) $100 million.
Borrowings under the Credit Facility bear interest at a rate equal to prime plus
0.50% or LIBOR plus 2.25%. As of March 31, 2004, $20.0 million in borrowings
were outstanding under the Credit Facility. The Credit Facility matures December
31, 2006 and is secured by substantially all of the Company's assets.
Effective December 31, 2003, the borrowing base under the Credit Facility
was increased to $40.0 million as a result of the acquisition of properties in
the Miller merger and our drilling activities since the last redetermination.
Available borrowing capacity under our facility was $20.0 million at March 31,
2004. We expect to redetermine our existing borrowing base in the second quarter
of 2004, and semiannually thereafter.
The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings, 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 (defined as EBITDA less similar
non-cash items and exploration and abandonment expenses for such period) 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 current liabilities, as defined in the agreement, be at least
$1.0 million. The Maximum Leverage ratio requires that the ratio, as of the last
day of any fiscal quarter, of (a) Total Indebtedness (as defined in the Credit
Facility) as of such fiscal quarter to (b) an amount equal to consolidated
EBITDAX for the two quarters then ended times two, shall not be greater than 3.0
to 1.0. Consolidated EBITDAX is a component of negotiated covenants with our
lenders and is presented here as part of the Company's disclosure of its
covenant obligations.
Off Balance Sheet Arrangements
We currently do not have any off balance sheet arrangements.
Contractual Cash Obligations
There were not material changes outside the ordinary course of our
business in lease obligations or other contractual obligations since December
31, 2003.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In December 2003, the FASB issued revised Interpretation No. 46 ("FIN
46R"), "Consolidation of Variable Interest Entities, an Interpretation of ARB
No. 51". FIN 46R requires a company to consolidate a variable interest entity,
as defined, when the company will absorb a majority of the variable interest
entity's expected losses, receive a majority of the variable interest entity's
expected residual returns, or both. FIN 46R also requires certain disclosures
relating to consolidated variable interest entities and unconsolidated variable
interest entities in which a company has a significant variable interest. The
provisions of FIN 46R are required for companies that have interests in variable
interest entities or potential variable interest entities commonly referred to
as special-purpose
24
entities for periods ending after December 15, 2003. The provisions of FIN 46R
are required to be applied for periods ending after March 15, 2004 for all other
types of entities. We share interests with related parties in a variety of
different partnership and joint venture entities in order to share the rewards
of ownership in certain oil and natural gas royalties. We do not provide
supplemental support to these entities nor do we own voting rights. In general,
these entities are structured such that the voting and sharing ratios in these
entities are consistent with the allocation of the entities' distributions of
cash from royalty revenues. We are not impacted by FIN 46R because we will not
absorb a majority of the expected losses or receive a majority of the expected
residual returns, as defined by FIN 46R, and accordingly we are not required to
consolidate these interests.
HEDGING ACTIVITIES
In August 2003, we purchased natural gas options that cover 10,000 MMbtu
per day for the period January 1, 2004 to December 31, 2004 at a floor of $4.50
per MMbtu and a ceiling of $7.00 per MMbtu for the first and fourth quarters of
2004 and $6.00 per MMbtu for the second and third quarters of 2004 for a cost of
$686,250. At March 31, 2004 the market value of this instrument was a liability
of approximately $668,600.
In December 2003, we entered into a costless natural gas collar covering
5,000 MMbtu per day for the period January 1, 2004 to March 31, 2004 with a
floor of $4.50 per MMbtu and a ceiling of $7.05 per MMbtu. The natural gas
collar expired with no cost to us.
In February 2004, we entered into a costless natural gas collar covering
5,000 MMbtu per day for the period April 1, 2004 to September 30, 2004 with a
floor of $4.50 per MMbtu and a ceiling of $6.20 per MMbtu. At March 31, 2004 the
market value of this instrument was a liability of approximately $197,300.
In March 2004, we entered into a costless natural gas collar covering
5,000 MMbtu per day for the period October 1, 2004 to December 31, 2004 with a
floor of $4.50 per MMbtu and a ceiling of $7.25 per MMbtu. At March 31, 2004 the
market value of this instrument was an asset of approximately $92,400 and is
netted against current liabilities.
In March 2004, we entered into a costless crude oil collar covering 400
barrels per day for the period April 1, 2004 to December 31, 2004 with a floor
of $30.00 per barrel and a ceiling of $35.50 per barrel. At March 31, 2004 the
market value of this instrument was a gain of approximately $45,500 and is
netted against current liabilities. Hedge accounting was not applicable to this
transaction so the associated gain will not be deferred in Other Comprehensive
Income, rather in oil and natural gas revenue.
TAX MATTERS
At December 31, 2003, we have cumulative net operating loss carryforwards
("NOLs") for federal income tax purposes of approximately $50.1 million,
including $17.4 million of NOLs acquired in the Miller acquisition that will
begin to expire in 2012. We currently anticipate that all of these NOLs will be
utilized in connection with federal income taxes payable in the future. 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.
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES 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 provide a benefit due to downward interest rate movements but does
not limit us to exposure from future increases in interest rates. Based
25
on the March 31, 2004 outstanding borrowings and a floating interest rate of
3.36%, a 10% change in interest rate would result in an increase or decrease of
interest expense of approximately $64,100 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. During
2003, due to the instability of prices and to achieve a more predictable cash
flow, we put in place two natural gas collars for a portion of our 2004
production. During the first quarter of 2004, we put in place two additional
natural gas collars and one crude oil collar. Please refer to Note 6 to our
consolidated financial statements. 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. At March 31, 2004, the fair
value of the outstanding hedges was a liability of approximately $728,000. A 10%
change in the commodity price per unit, as long as the price is either above the
ceiling or below the floor price would cause the fair value total of the hedge
to increase or decrease by approximately $95,800.
ITEM 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of March 31, 2004 to provide reasonable assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms.
There has been no change in our internal controls over financial reporting that
occurred during the three months ended March 31, 2004 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
26
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 the Company, could have a
potential material adverse effect on our financial condition, results of
operations or cash flows.
ITEM 2 - CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES
(C) RECENT SALES OF UNREGISTERED SECURITIES
On March 2, 2004, we issued 45,000 shares of our Common Stock in
connection with the exercise of warrants, which had originally been sold in May
of 1999 to an IRA for the benefit of John Elias (the "Elias IRA"). The aggregate
purchase price for the shares of Common Stock issued to the Elias IRA was
$240,750. The sale of the shares of Common Stock pursuant to the exercise of the
related warrants to the Elias IRA, was exempt from the 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. The Company has previously
filed a registration statement with the SEC registering the resale of the Common
Stock described above under the Securities Act of 1933 as amended.
ITEM 3 - DEFAULTS UPON SENIOR SECURITIES.............................. None
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......... None
ITEM 5 - OTHER INFORMATION............................................ None
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS. 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)).
2.2 -- Agreement and Plan of Merger dated as of May 28, 2003 among
Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller
Exploration Company (Miller") (Incorporated by reference from
Annex A to the Joint Proxy Statement/Prospectus contained in
the Company's Registration Statement on Form S-4/A filed on
October 31, 2003 (Registration No. 333-106484)).
3.1 -- Restated Certificate of Incorporation of the Company
(Incorporated by reference from exhibit 3.1 to the Company's
Registration Statement on Form S-1/A filed on February 5, 1997
(Registration No. 333-17267)).
3.2 -- Certificate of Amendment to the Restated Certificate of
Incorporation of the Company (Incorporated by reference from
exhibit 3.1 to the Company's Registration Statement on Form
S-1/A filed on February 5, 1997 (Registration No. 333-17267)).
27
3.3 -- 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).
3.4 -- 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).
3.5 -- Second Amendment to Bylaws of the Company on May 7, 2003
(Incorporated by reference from exhibit 3.4 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended March
31, 2003).
*4.1 -- Third Amended and Restated Credit Agreement dated December 31, 2003
by and between Edge Petroleum Corporation, Edge Petroleum
Exploration Company, Edge Petroleum Operating Company, Inc., Miller
Oil Corporation, and Miller Exploration Company, as borrowers, and
Union Bank of California, N.A., a national banking association, as
Agent for itself and as lender.
4.2 -- 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).
4.3 -- 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).
4.4 -- 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).
4.5 -- Registration Rights Agreement by and among Edge, Guardian Energy
Management Corp., Kelly E. Miller and the Debra A. Miller Trust,
dated December 4, 2003 (Incorporated by reference from exhibit 4.2
of the Company's Registration Statement on Form S-3 filed on
February 3, 2004 (Registration No. 333-112462)).
4.6 -- Securities Purchase Agreement between Miller and Guardian Energy
Management Corp., dated July 11, 2000 (Incorporated by reference
from exhibit 10.1 to Miller's Current Report on Form 8-K, filed on
July 25, 2000).
4.7 -- Warrant between Miller and Guardian Energy Management Corp., dated
July 11, 2000, exercisable for 900,000 shares of Miller's common
stock (as adjusted for the one for ten reverse stock split of Miller
effected October 11, 2002 and as adjusted pursuant to the Agreement
and Plan of Merger by and among the Company, Edge Delaware Sub Inc.
and Miller) (incorporated by reference from Exhibit 4.3 to Miller's
Current Report on Form 8-K filed on July 25, 2000).
4.8 -- Miller Exploration Company Stock Option and Restricted Stock Plan of
1997 (Incorporated by reference from exhibit 10.1(a) to Miller's
Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 000-23431)).
4.9 -- Amendment No. 1 to the Miller Exploration Company Stock Option and
Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit
4.2 from Miller's Registration Statement on Form S-8 filed on April
11, 2001 (Registration No. 333-58678)).
4.10 -- Amendment No. 2 to the Miller Exploration Company Stock Option and
Restricted Stock Plan of 1997 (Incorporated by reference from
Exhibit 4.3 to Miller's Registration Statement on Form S-8 filed on
April 11, 2001 (Registration No. 333-58678)).
28
4.11 -- Form of Miller Stock Option Agreement (Incorporated by reference
from exhibit 10.1(b) to Miller's Annual Report on Form 10-K for the
year ended December 31, 1997 (File No. 000-23431)).
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 -- Amendment dated August 21, 2000 to the 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 10.3 to the Company's Annual Report on Form 10-K/A for the
year ended December 31, 2002).
10.4 -- Amendment dated August 21, 2000 to the Joint Venture Agreement
between Edge Joint Venture II and Essex Royalty Limited Partnership,
dated as of April 11, 1992. (Incorporated by reference from exhibit
10.2 to the Company's Annual Report on Form 10-K/A for the year
ended December 31, 2002).
10.5 -- Letter Agreement between Edge Petroleum Corporation and Essex
Royalty Limited Partnership, dated as of July 30, 2002.
(Incorporated by reference from exhibit 10.4 to the Company's Annual
Report on Form 10-K/A for the year ended December 31, 2002).
10.6 -- 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)).
10.7 -- 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)).
10.8 -- 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).
10.9 -- Incentive Plan of Edge Petroleum Corporation as Amended and Restated
Effective as of December 4, 2003. (Incorporated by reference from
exhibit 4.1 to the Company's Registration Statement on Form S-8
(Registration No. 333 - 113619).
10.10 -- 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).
10.11 -- 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).
10.12 -- Severance Agreements by and between Edge Petroleum Corporation and
the Officers of the Company named herein. (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).
29
10.13 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated by
reference from exhibit 10.15 to the Company's Quarterly Report on
Form 10-Q/A for the quarterly period ended March 31, 1999).
10.14 -- 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)).
10.15 -- 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)).
*31.1 -- Certification by John W. Elias, Chief Executive Officer, pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2 -- Certification by Michael G. Long, Chief Financial Officer, pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1 -- Certification by John W. Elias, Chief Executive Officer, pursuant to
18 USC Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
*32.2 -- Certification by Michael G. Long, Chief Financial Officer, pursuant
to 18 USC Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
*Filed herewith.
(B) Reports on Form 8-K
The Company filed a Current Report on Form 8-K January 20, 2004
(information furnished not filed) announcing the issuance of a press release
reporting its 2003 operating results and updating recent activity and guidance
and attaching a copy of the press release as an exhibit.
The Company filed a Current Report on Form 8-K on February 4, 2004
(information furnished not filed) announcing its presentation to institutional
investors and attaching a copy of the related slide presentation as an exhibit.
The Company filed a Current Report on Form 8-K on February 12, 2004
(information furnished not filed) announcing the issuance of a press release
reporting an update on the company's recent operational activities and future
drilling plans and attaching a copy of the press release as an exhibit.
The Company filed a Current Report on Form 8-K/A on February 17, 2004 to
include the historical and pro forma information related to the acquisition of
Miller Exploration Company.
The Company filed a Current Report on Form 8-K on March 15, 2004
(information furnished not filed) announcing the issuance of a press release
announcing financial results for the fourth quarter and full-year of 2003,
updated operations and provided 2004 guidance and attaching a copy of the press
release as an exhibit.
30
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 May 11, 2004 /s/ John W. Elias
----------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board
Date May 11, 2004 /s/ Michael G. Long
----------------------------------
Michael G. Long
Senior Vice President and
Chief Financial and Accounting Officer
31
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 Incorporation of the Company (Incorporated
by reference from exhibit 3.1 to the Company's Registration
Statement on Form S-1/A filed on February 5, 1997 (Registration No.
333-17267)).
3.2 -- Certificate of Amendment to the Restated Certificate of
Incorporation of the Company (Incorporated by reference from exhibit
3.1 to the Company's Registration Statement on Form S-1/A filed on
February 5, 1997 (Registration No. 333-17267)).
3.3 -- 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).
3.4 -- First Amendment to Bylaws of the Company on September 28, 1999
(Incorporated by Reference from exhibit 3.4 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended March
31, 2003).
3.5 -- Second Amendment to Bylaws of the Company on May 7, 2003
(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 -- Third Amended and Restated Credit Agreement dated as of December 31,
2003 among Edge Petroleum Corporation, Edge Petroleum Exploration
Company, Edge Petroleum Operating Company, Inc., Miller Oil
Corporation and Miller Exploration Company (collectively, the
"Borrowers") the lenders party thereto and Union Bank Of California,
N.A., a national banking association, as Agent.
4.2 -- 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).
4.3 -- 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).
4.4 -- 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).
4.5 -- Registration Rights Agreement by and among Edge, Guardian Energy
Management Corp., Kelly E. Miller and the Debra A. Miller Trust,
dated December 4, 2003 (Incorporated by reference from exhibit 4.2
of the Company's Registration Statement on Form S-3 filed on
February 3, 2004 (Registration No. 333-112462)).
4.6 -- Securities Purchase Agreement between Miller and Guardian Energy
Management Corp., dated July 11, 2000 (Incorporated by reference
from exhibit 10.1 to Miller's Current Report on Form 8-K, filed on
July 25, 2000).
4.7 -- Warrant between Miller and Guardian Energy Management Corp., dated
July 11, 2000, exercisable for 900,000 shares of Miller's common
stock (as adjusted for the one for ten reverse stock split of
32
Miller effected October 11, 2002 and as adjusted pursuant to the
Agreement and Plan of Merger by and among the Company, Edge Delaware
Sub Inc. and Miller) (incorporated by reference from Exhibit 4.3 to
Miller's Current Report on Form 8-K filed on July 25, 2000).
4.8 -- Miller Exploration Company Stock Option and Restricted Stock Plan of
1997 (Incorporated by reference from exhibit 10.1(a) to Miller's
Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 000-23431)).
4.9 -- Amendment No. 1 to the Miller Exploration Company Stock Option and
Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit
4.2 from Miller's Registration Statement on Form S-8 filed on April
11, 2001 (Registration No. 333-58678)).
4.10 -- Amendment No. 2 to the Miller Exploration Company Stock Option and
Restricted Stock Plan of 1997 (Incorporated by reference from
Exhibit 4.3 to Miller's Registration Statement on Form S-8 filed on
April 11, 2001 (Registration No. 333-58678)).
4.11 -- Form of Miller Stock Option Agreement (Incorporated by reference
from exhibit 10.1(b) to Miller's Annual Report on Form 10-K for the
year ended December 31, 1997 (File No. 000-23431)).
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 -- Amendment dated August 21, 2000 to the 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 10.3 to the Company's Annual Report on Form 10-K/A for the
year ended December 31, 2002).
10.4 -- Amendment dated August 21, 2000 to the Joint Venture Agreement
between Edge Joint Venture II and Essex Royalty Limited Partnership,
dated as of April 11, 1992. (Incorporated by reference from exhibit
10.4 to the Company's Annual Report on Form 10-K/A for the year
ended December 31, 2002).
10.5 -- Letter Agreement between Edge Petroleum Corporation and Essex
Royalty Limited Partnership, dated as of July 30, 2002.
(Incorporated by reference from exhibit 10.5 to the Company's Annual
Report on Form 10-K/A for the year ended December 31, 2002).
10.6 -- 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)).
10.7 -- 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)).
10.8 -- 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).
33
10.9 -- Incentive Plan of Edge Petroleum Corporation as Amended and Restated
Effective as of December 4, 2003. (Incorporated by reference from
exhibit 4.1 to the Company's Registration Statement on Form S-8
filed March 15, 2004.
10.10 -- 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).
10.11 -- 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).
10.12 -- Severance Agreements by and between Edge Petroleum Corporation and
the Officers of the Company named herein. (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).
10.13 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated by
Reference from exhibit 10.15 to the Company's Quarterly Report on
Form 10-Q/A for the quarterly period ended March 31, 1999).
10.14 -- 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)).
10.15 -- 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)).
*31.1 -- Certification by John W. Elias, Chief Executive Officer, pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act
of 1934.
*31.2 -- Certification by Michael G. Long , Chief Financial and Accounting
Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934.
*32.1 -- Certification by John W. Elias, Chief Executive Officer, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and
(b) of Section 1350, Chapter 63 of Title 18, United States Code).
*32.2 -- Certification by Michael G. Long, Chief Financial and Accounting
Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18,
United States Code).
* Filed herewith.
34