UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended: June 30, 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: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-597-7000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 and 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 [X] No [ ]
Number of shares of common stock outstanding at August 4, 2004 79,201,084
Page 1 of 37
THE MERIDIAN RESOURCE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
INDEX
Page
Number
------
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Operations (unaudited) for the
Three Months and Six Months Ended June 30, 2004 and 2003 3
Consolidated Balance Sheets as of June 30, 2004 (unaudited)
and December 31, 2003 4
Consolidated Statements of Cash Flows (unaudited) for the
Six Months Ended June 30, 2004 and 2003 6
Consolidated Statements of Stockholders' Equity (unaudited) for the
Six Months Ended June 30, 2004 and 2003 7
Consolidated Statements of Comprehensive Income (unaudited) for the
Three Months and Six Months Ended June 30, 2004 and 2003 8
Notes to Consolidated Financial Statements (unaudited) 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk 28
Item 4. Controls and Procedures 29
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 30
Item 6. Exhibits and Reports on Form 8-K 30
SIGNATURES 31
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share information)
(unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------- -------
2004 2003 2004 2003
-------- -------- -------- --------
REVENUES:
Oil and natural gas $ 50,065 $ 29,603 $ 96,205 $ 58,590
Interest and other 38 51 90 89
-------- -------- -------- --------
50,103 29,654 96,295 58,679
-------- -------- -------- --------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 2,746 2,803 5,754 5,287
Severance and ad valorem taxes 2,512 1,548 4,829 3,367
Depletion and depreciation 25,352 15,187 49,053 29,842
Accretion expense 148 128 267 256
General and administrative 3,491 2,972 6,695 5,782
-------- -------- -------- --------
34,249 22,638 66,598 44,534
-------- -------- -------- --------
EARNINGS BEFORE INTEREST AND INCOME TAXES 15,854 7,016 29,697 14,145
-------- -------- -------- --------
OTHER EXPENSES:
Interest expense 1,801 3,468 3,970 5,944
Debt conversion expense -- -- 1,188 --
-------- -------- -------- --------
1,801 3,468 5,158 5,944
-------- -------- -------- --------
EARNINGS BEFORE INCOME TAXES 14,053 3,548 24,539 8,201
-------- -------- -------- --------
INCOME TAXES:
Current 1,100 -- 2,100 --
Deferred 4,100 -- 7,000 --
-------- -------- -------- --------
5,200 -- 9,100 --
-------- -------- -------- --------
EARNINGS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE: 8,853 3,548 15,439 8,201
Cumulative effect of change in accounting principle -- -- -- (1,309)
-------- -------- -------- --------
NET EARNINGS: 8,853 3,548 15,439 6,892
Dividends on preferred stock 1,108 1,624 2,407 3,247
-------- -------- -------- --------
NET EARNINGS APPLICABLE
TO COMMON STOCKHOLDERS $ 7,745 $ 1,924 $ 13,032 $ 3,645
======== ======== ======== ========
NET EARNINGS PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
Basic $ 0.11 $ 0.04 $ 0.20 $ 0.10
Diluted $ 0.10 $ 0.04 $ 0.18 $ 0.10
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
ACCOUNTING PRINCIPLE PER SHARE:
Basic and Diluted $ -- $ -- $ -- $ (0.03)
-------- -------- -------- --------
NET EARNINGS PER SHARE:
Basic $ 0.11 $ 0.04 $ 0.20 $ 0.07
======== ======== ======== ========
Diluted $ 0.10 $ 0.04 $ 0.18 $ 0.07
======== ======== ======== ========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 69,304 50,163 66,157 50,126
======== ======== ======== ========
Diluted 75,363 50,163 73,566 50,126
======== ======== ======== ========
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
JUNE 30, DECEMBER 31,
2004 2003
---------- ----------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 11,803 $ 12,821
Accounts receivable, less allowance for doubtful accounts of
$249 [2004] and $251 [2003] 23,745 24,703
Due from affiliates 224 349
Prepaid expenses and other 2,947 1,586
Assets from price risk management activities 976 584
---------- ----------
Total current assets 39,695 40,043
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$38,536 [2004] and $30,542 [2003] not
subject to depletion) 1,290,119 1,230,643
Land 478 478
Equipment and other 10,011 9,931
---------- ----------
1,300,608 1,241,052
Less accumulated depletion and depreciation 885,189 836,368
---------- ----------
Total property and equipment, net 415,419 404,684
---------- ----------
OTHER ASSETS 2,017 4,022
---------- ----------
Total assets $ 457,131 $ 448,749
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
JUNE 30, DECEMBER 31,
2004 2003
--------- ---------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 9,752 $ 8,692
Revenues and royalties payable 8,371 13,087
Notes payable 1,597 194
Accrued liabilities 12,699 12,074
Liabilities from price risk management activities 13,329 9,768
Abandonment costs 589 953
Current income taxes payable 2,300 415
Current portion long-term debt 5,000 10,000
--------- ---------
Total current liabilities 53,637 55,183
--------- ---------
LONG-TERM DEBT 114,000 122,320
--------- ---------
9 1/2% CONVERTIBLE SUBORDINATED NOTES -- 20,000
--------- ---------
OTHER:
Liabilities from price risk management activities 708 2,385
Abandonment costs 3,381 3,149
Deferred income taxes 7,409 931
--------- ---------
11,498 6,465
--------- ---------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
323,710 [2004] and 604,460 [2003] shares of Series C
Redeemable Convertible Preferred Stock issued at stated value) 32,371 60,446
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
72,281,091 [2004] and 61,724,597 [2003] issued) 751 644
Additional paid-in capital 443,388 394,177
Accumulated deficit (189,460) (202,492)
Accumulated other comprehensive loss (8,674) (7,704)
Unamortized deferred compensation (380) (290)
--------- ---------
Total stockholders' equity 245,625 184,335
--------- ---------
Total liabilities and stockholders' equity $ 457,131 $ 448,749
========= =========
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
SIX MONTHS ENDED
JUNE 30,
-------
2004 2003
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 15,439 $ 6,892
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Cumulative effect of change in accounting principle -- 1,309
Debt conversion expense 1,188 --
Depletion and depreciation 49,053 29,842
Amortization of other assets 971 852
Non-cash compensation 835 676
Accretion expense 267 256
Deferred income taxes 7,000 --
Changes in assets and liabilities:
Accounts receivable 958 (4,665)
Due from affiliates 125 528
Prepaid expenses and other (1,361) (1,243)
Accounts payable 1,060 (2,229)
Revenues and royalties payable (4,716) 2,048
Accrued liabilities and other 3,488 1,153
-------- --------
Net cash provided by operating activities 74,307 35,419
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (59,620) (31,669)
Sale of property and equipment (125) 39
-------- --------
Net cash used in investing activities (59,745) (31,630)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term debt (13,320) (1,250)
Net payments of notes payable 1,403 252
Issuance of stock/exercise of options 222 180
Payment of preferred dividends (3,872) --
Additions to deferred loan costs (13) (126)
-------- --------
Net cash used in financing activities (15,580) (944)
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,018) 2,845
Cash and cash equivalents at beginning of period 12,821 7,287
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 11,803 $ 10,132
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Non-cash financing activities:
Conversion of preferred stock $(28,075) $ --
Conversion of convertible subordinated debt $(20,000) $ --
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SIX MONTHS ENDED JUNE 30, 2004 AND 2003
(in thousands)
(unaudited)
Common Stock Accumulated
--------------------- Additional Accumulated Other Unamortized
Shares Paid-In Earnings Comprehensive Deferred
Value Par Capital (Deficit) Loss Compensation
-------- --------- --------- --------- --------- ---------
Balance, December 31, 2002 50,089 $ 557 $ 378,215 $(209,738) $ (4,938) $ (356)
Issuance of rights to common
stock -- 7 625 -- -- (632)
Company's 401(k) plan
contribution 93 -- (569) -- -- --
Exercise of stock options 1 -- (9) -- -- --
Compensation expense -- -- -- -- -- 676
Accum. other comprehensive loss -- -- -- -- (3,445) --
Preferred dividends -- -- -- (2,962) -- --
Net earnings -- -- -- 6,606 -- --
-------- --------- --------- --------- --------- ---------
Balance, June 30, 2003 50,183 $ 564 $ 378,262 $(206,094) $ (8,383) $ (312)
======== ========= ========= ========= ========= =========
Balance, December 31, 2003 61,725 $ 644 $ 394,177 $(202,492) $ (7,704) $ (290)
Issuance of rights to common
stock -- 2 923 -- -- (925)
Company's 401(k) plan
contribution 31 -- 185 -- -- --
Exercise of stock options 8 -- 37 -- -- --
Compensation expense -- -- -- -- -- 835
Accum. other comprehensive
loss -- -- -- -- (970) --
Issuance for conversion of
pref stock 6,308 63 26,920 -- -- --
Issuance for conversion of sub
debt 4,209 42 21,146 -- -- --
Preferred dividends -- -- -- (2,407) -- --
Net earnings -- -- -- 15,439 -- --
-------- --------- --------- --------- --------- ---------
Balance, June 30, 2004 72,281 $ 751 $ 443,388 $(189,460) $ (8,674) $ (380)
======== ========= ========= ========= ========= =========
Treasury Stock
---------------------
Shares Cost Total
------- --------- ---------
Balance, December 31, 2002 3,779 $ (30,347) $ 133,393
Issuance of rights to common
stock -- -- --
Company's 401(k) plan
contribution (93) 747 178
Exercise of stock options (1) 12 3
Compensation expense -- -- 676
Accum. other comprehensive loss -- -- (3,445)
Preferred dividends -- -- (2,962)
Net earnings -- -- 6,606
------- --------- ---------
Balance, June 30, 2003 3,685 $ (29,588) $ 134,449
======= ========= =========
Balance, December 31, 2003 -- $ -- $ 184,335
Issuance of rights to common
stock -- -- --
Company's 401(k) plan
contribution -- -- 185
Exercise of stock options -- -- 37
Compensation expense -- -- 835
Accum. other comprehensive
loss -- -- (970)
Issuance for conversion of
pref stock -- -- 26,983
Issuance for conversion of sub
debt -- -- 21,188
Preferred dividends -- -- (2,407)
Net earnings -- -- 15,439
------- --------- ---------
Balance, June 30, 2004 -- $ -- 245,625
======= ========= =========
See notes to consolidated financial statements.
7
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(thousands of dollars)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2004 2003 2004 2003
-------- -------- -------- --------
Net earnings applicable to common stockholders $ 7,745 $ 1,924 $ 13,032 $ 3,645
Other comprehensive income (loss), net of tax, for unrealized losses from
hedging activities:
Unrealized holding losses arising during period (2,445) (5,028) (6,080) (10,030)
Reclassification adjustments on settlement of contracts 2,760 3,662 5,110 6,585
-------- -------- -------- --------
315 (1,366) (970) (3,445)
-------- -------- -------- --------
Total comprehensive income $ 8,060 $ 558 $ 12,062 $ 200
======== ======== ======== ========
See notes to consolidated financial statements.
8
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The consolidated financial statements reflect the accounts of The Meridian
Resource Corporation and its subsidiaries (the "Company") after elimination of
all significant intercompany transactions and balances. The financial statements
should be read in conjunction with the consolidated financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the year
ended December 31, 2003, as filed with the Securities and Exchange Commission.
The financial statements included herein as of June 30, 2004, and for the three
and six month periods ended June 30, 2004 and 2003, are unaudited, and in the
opinion of management, the information furnished reflects all material
adjustments, consisting of normal recurring adjustments, necessary for a fair
presentation of financial position and of the results for the interim periods
presented. Certain minor reclassifications of prior period statements have been
made to conform to current reporting practices. The results of operations for
interim periods are not necessarily indicative of results to be expected for a
full year.
2. DEBT
CREDIT FACILITY. During August 2002, the Company replaced its Chase Manhattan
Bank Credit Facility with a new three-year $175 million underwritten senior
secured credit agreement (the "Credit Agreement") with Societe Generale as
administrative agent, lead arranger and book runner, and Fortis Capital
Corporation, as co-lead arranger and documentation agent. Borrowings under the
Credit Agreement mature on August 13, 2005. The borrowing base is currently set
at $127.5 million effective on July 31, 2004. Credit facility payments of $8.3
million have been made during the first six months of 2004, bringing the
outstanding balance to $114 million as of June 30, 2004. In August 2004, the
Company made $40.0 million in debt repayments and anticipates that it will
continue to make additional debt repayments during the remainder of the year.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders or borrower, under the Credit Agreement, have the right to redetermine
the borrowing base at any time, once during each calendar year. Borrowings under
the Credit Agreement are secured by pledges of outstanding capital stock of the
Company's subsidiaries and a mortgage on the Company's oil and natural gas
properties of at least 90% of its present value of proved properties. The Credit
Agreement contains various restrictive covenants, including, among other items,
maintenance of certain financial ratios and restrictions on cash dividends on
Common Stock and under certain circumstances Preferred Stock, and an unqualified
audit report on the Company's consolidated financial statements.
Under the Credit Agreement, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus 1/2
of 1%, plus an additional 0.5% to 1.5% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At June 30, 2004, the three-month LIBOR interest rate was
1.61%. The Credit Agreement also provides for commitment fees ranging from
0.375% to 0.5% per annum.
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended a short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million on
April 5, 2002, with a maturity date of
9
December 31, 2004. The notes are unsecured and contain customary events of
default, but do not contain any maintenance or other restrictive covenants. The
interest rate is LIBOR plus 5.5% from January 1, 2003, through August 31, 2003,
and LIBOR plus 6.5% from September 1, 2003, through December 31, 2004. At June
30, 2004, the three-month LIBOR interest rate was 1.61%. A note payment of $5
million was made during April 2004, with the remaining $5 million payable on
December 31, 2004. The Company is in compliance with the terms of this
agreement.
9 1/2% CONVERTIBLE SUBORDINATED NOTES. During March 2004, the notes were
converted into 4.0 million shares of the Company's Common Stock at a conversion
price of $5.00 per share, and included an additional non-cash conversion expense
of approximately $1.2 million that was incurred and paid via the issuance of
Common Stock priced at market.
3. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK
A private placement of $66.85 million of 8.5% redeemable convertible preferred
stock was completed during May 2002. The preferred stock is convertible into
shares of the Company's Common Stock at a conversion price of $4.45 per share.
Dividends are payable semi-annually in cash or additional preferred stock. At
the option of the Company, one-third of the preferred shares can be forced to
convert to Common Stock if the closing price of the Company's Common Stock
exceeds 150% of the conversion price for 30 out of 40 consecutive trading days
on the New York Stock Exchange. The preferred stock is subject to redemption at
the option of the Company after March 2005, and mandatory redemption on March
31, 2009. The holders of the preferred stock have been granted registration
rights with respect to the shares of Common Stock issued upon conversion of the
preferred stock.
In June 2004, the Company exercised its right, as described above, to convert
one-third of its remaining issued and outstanding preferred stock into shares of
Common Stock. The conversion was completed on a pro rata basis and included a
cash payment for accrued and unpaid dividends through the June 8, 2004,
conversion date, at which time dividends ceased to accrue on the converted
shares. Based on this conversion and other voluntary conversions, the
outstanding Series C preferred stock has been reduced from a high stated value
of approximately $72.7 million as of June 30, 2003 to approximately $32.4
million as of June 30, 2004, representing a future cash savings in dividends of
approximately $3.4 million on an annualized basis.
4. COMMITMENTS AND CONTINGENCIES
LITIGATION.
ENVIRONMENTAL LITIGATION. Various landowners have filed claims against the
Company and numerous other oil companies in four similar lawsuits concerning the
Weeks Island, Gibson, Bayou Pigeon and Napoleonville Fields. The lawsuits seek
injunctive relief and other relief, including unspecified amounts in both actual
and punitive damages for alleged breaches of mineral leases and alleged failure
to restore the plaintiffs' lands from alleged contamination and otherwise from
the defendants' oil and gas operations.
There are no other material legal proceedings which exceeds our insurance limits
to which the Company or any of its subsidiaries is a party or to which any of
its property is subject, other than ordinary and routine litigation incidental
to the business of producing and exploring for crude oil and natural gas.
10
5. STOCKHOLDERS' EQUITY
COMMON STOCK. In August 2003, the Company completed a private offering of
8,703,537 shares of Common Stock at a price of $3.87 per share. The total
proceeds of the offering, net of issuance costs, received by the Company were
approximately $33.0 million. The Company used the majority of these funds to
retire $31.8 million in long-term debt, with the remainder of the proceeds being
used for exploration activities and other general corporate purposes. As
previously noted, during the six months ended June 30, 2004, approximately 6.3
million shares of Common Stock were issued upon the conversion of a portion of
the 8.5% Redeemable Convertible Preferred Stock and approximately 4.2 million
shares of Common Stock was issued for the early retirement of the 9 1/2%
Convertible Subordinated Notes.
11
6. EARNINGS PER SHARE (in thousands, except per share)
The following tables set forth the computation of basic and diluted net earnings
per share:
THREE MONTHS ENDED JUNE 30,
2004 2003
--------- ---------
Numerator:
Net earnings applicable to common stockholders $ 7,745 $ 1,924
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes -- N/A
--------- ---------
Net earnings applicable to common stockholders
plus assumed conversions $ 7,745 $ 1,924
--------- ---------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 69,304 50,163
Effect of potentially dilutive common shares:
Warrants 4,443 N/A
Employee and director stock options 1,616 N/A
Convertible subordinated notes -- N/A
Redeemable preferred stock N/A N/A
--------- ---------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 75,363 50,163
========= =========
Basic earnings per share $ 0.11 $ 0.04
========= =========
Diluted earnings per share $ 0.10 $ 0.04
========= =========
SIX MONTHS ENDED JUNE 30,
2004 2003
-------- ---------
Numerator:
Net earnings applicable to common stockholders $ 13,032 $ 3,645
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes 270 N/A
-------- ---------
Net earnings applicable to common stockholders
plus assumed conversions $ 13,302 $ 3,645
-------- ---------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 66,157 50,126
Effect of potentially dilutive common shares:
Warrants 4,240 N/A
Employee and director stock options 1,455 N/A
Convertible subordinated notes 1,714 N/A
Redeemable preferred stock N/A N/A
-------- ---------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 73,566 50,126
======== =========
Basic earnings per share $ 0.20 $ 0.07
======== =========
Diluted earnings per share $ 0.18 $ 0.07
======== =========
12
7. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments with value
fluctuations which correlate strongly with the underlying commodity being
hedged. The Company enters into swaps and other derivative contracts to hedge
the price risks associated with a portion of anticipated future oil and gas
production. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for our hedged production.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at or
prior to expiration or are exchanged for physical delivery contracts. The
Company does not obtain collateral to support the agreements, but monitors the
financial viability of counter-parties and believes its credit risk is minimal
on these transactions. In the event of nonperformance, the Company would be
exposed to price risk. The Company has some risk of accounting loss since the
price received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of the
hedging transaction.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various swap
agreements. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, these derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended. These
swaps have been designated as cash flow hedges as provided by FAS 133 and any
changes in fair value are recorded in other comprehensive income until earnings
are affected by the variability in cash flows of the designated hedged item. Any
changes in fair value resulting from the ineffectiveness of the hedge are
reported in the consolidated statement of operations as a component of revenues.
The estimated June 30, 2004, fair value of the Company's oil and natural gas
swaps was an unrealized loss of $13.1 million ($8.5 million net of tax) which is
recognized in other comprehensive income. Based upon June 30, 2004, oil and
natural gas commodity prices, approximately $12.5 million of the loss deferred
in other comprehensive income could potentially lower gross revenues over the
next twelve months. The swap agreements expire at various dates through July 31,
2005.
Net settlements under these swap agreements reduced oil and natural gas revenues
by $4,247,000 and $3,026,000 for the three months ended June 30, 2004 and 2003,
respectively, and by $7,861,000 and $10,131,000 for the six months ended June
30, 2004 and 2003, respectively, as a result of hedging transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 9% of our proved developed natural gas production and 62% of our
proved developed oil production during the respective terms of the swap
agreements. The fair values of the hedges are based on the difference between
the strike price and the New York Mercantile Exchange future prices for the
applicable trading months.
The estimated fair value of our oil and natural gas hedges as of June 30, 2004,
is provided below:
13
Weighted Average Fair Value (unrealized)
Notional Strike Price at June 30, 2004
Amount ($ per unit) (in thousands)
--------- ---------------- ----------------------
Natural Gas (mmbtu)
July 2004 - June 2005 2,230,000 $ 3.73 $ (5,622)
Oil (bbls)
July 2004 - July 2005 588,000 $ 23.38 (7,438)
------------
$ (13,060)
------------
8. STOCK-BASED COMPENSATION
SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure,"
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. As provided
for under SFAS 123, there has been no amount of compensation expense recognized
for the Company's stock option plans. The Company accounts for stock-based
compensation using the intrinsic value method prescribed in Accounting
Principles Board Opinion 25, "Accounting for Stock Issued to Employees."
Compensation expense is recorded for restricted stock awards over the requisite
vesting periods based upon the market value on the date of the grant. No
stock-based compensation expense was recorded in the three and six month periods
ended June 30, 2004 and 2003.
The following is a reconciliation of reported earnings and earnings per share as
if the Company used the fair value method of accounting for stock-based
compensation. Fair value is calculated using the Black-Scholes option-pricing
model.
(In thousands, except per share data)
Three Months Ended June 30,
---------------------------
2004 2003
--------- ---------
Net earnings applicable to common stockholders as reported $ 7,745 $ 1,924
Stock-based compensation (expense) benefit determined under
fair value method for all awards, net of tax (4) 16
--------- ---------
Net earnings applicable to common stockholders pro forma $ 7,741 $ 1,940
========= =========
Basic earnings per share:
As reported $ 0.11 $ 0.04
Pro forma $ 0.11 $ 0.04
Diluted earnings per share:
As reported $ 0.10 $ 0.04
Pro forma $ 0.10 $ 0.04
14
(In thousands, except per share data)
Six Months Ended June 30,
-------------------------
2004 2003
---------- ----------
Net earnings applicable to common stockholders as reported $ 13,032 $ 3,645
Stock-based compensation (expense) benefit determined under
fair value method for all awards, net of tax (8) 32
---------- ----------
Net earnings applicable to common stockholders pro forma $ 13,024 $ 3,677
========== ==========
Basic earnings per share:
As reported $ 0.20 $ 0.07
Pro forma $ 0.20 $ 0.07
Diluted earnings per share:
As reported $ 0.18 $ 0.07
Pro forma $ 0.18 $ 0.07
9. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
The fair value of asset retirement obligation liabilities has been calculated
using an expected present value technique. Fair value, to the extent possible,
should include a market risk premium for unforeseeable circumstances. No market
risk premium was included in the Company's asset retirement obligations fair
value estimate since a reasonable estimate could not be made. When the liability
is initially recorded, the entity increases the carrying amount of the related
long-lived asset. Over time, accretion of the liability is recognized each
period, and the capitalized cost is amortized over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement.
This standard requires the Company to record a liability for the fair value of
our dismantlement and abandonment costs, excluding salvage values.
Upon adoption, the Company recorded transition amounts for liabilities related
to our wells, and the associated costs to be capitalized. A liability of $4.5
million was recorded to long-term liabilities and a net asset of $3.2 million
was recorded to oil and natural gas properties on January 1, 2003. This resulted
in a cumulative effect of an accounting change of ($1.3) million. Accretion
expenses subsequent to the adoption of this accounting statement decreased net
earnings $267 thousand and $256 thousand in the first six months of 2004 and
2003, respectively.
15
The pro forma effect of the application of SFAS 143 as if the statement had been
adopted on January 1, 2002, is presented below (thousands of dollars except per
share information):
Three Months Ended June 30, Six Months Ended June 30,
-------------------------- ------------------------
2004 2003 2004 2003
---------- ---------- ---------- -------
Net earnings applicable to common
stockholders $ 7,745 $ 1,924 $ 13,032 $ 3,645
Additional accretion expense -- -- -- --
Cumulative effect of accounting change -- -- -- 1,309
---------- ---------- ---------- -------
Pro forma net earnings $ 7,745 $ 1,924 $ 13,032 $ 4,954
Basic $ 0.11 $ 0.04 $ 0.20 $ 0.10
Diluted $ 0.10 $ 0.04 $ 0.18 $ 0.10
The following table describes the change in the Company's asset retirement
obligations for the period ended June 30, 2004, and the pro forma amounts for
the year ended December 31, 2002 (thousands of dollars):
Asset retirement obligation at December 31, 2002 $ 4,523
Additional retirement obligations recorded in 2003 338
Reduction due to property sale in 2003 (1,010)
Other revisions during 2003 (416)
Accretion expense for 2003 667
--------
Asset retirement obligation at December 31, 2003 4,102
--------
Additional retirement obligations recorded in 2004 61
Other revisions during 2004 (460)
Accretion expense for 2004 267
--------
Asset retirement obligation at June 30, 2004 $ 3,970
========
10. NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the FASB issued SFAS No. 141, "Business Combinations" and SFAS No.
142, "Goodwill and Other Intangible Assets." SFAS No. 141 addresses accounting
and reporting for business combinations and is effective for all business
combinations initiated after June 30, 2001. SFAS No. 142 addresses the
accounting and reporting for goodwill subsequent to acquisition and other
intangible assets. The new standard eliminates the requirement to amortize
acquired goodwill; instead, such goodwill is required to be reviewed at least
annually for 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. The adoption of SFAS No. 141 and SFAS No. 142 had no impact on
the Company's financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recognized in the period in which it is incurred if
a reasonable estimate of fair value can be made. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
SFAS No. 143 was effective for the Company on January 1, 2003. See Note 9 for
discussion of the impact on the Company's consolidated financial statements.
During December 2003, the FASB issued Interpretation No. 46R, "Consolidation of
Variable Interest Entities" ("FIN 46"), which requires the consolidation of
certain entities that are determined to be variable interest entities ("VIE's").
An entity is considered to be a VIE when either (i) the entity lacks sufficient
16
equity to carry on its principal operations, (ii) the equity owners of the
entity cannot make decisions about the entity's activities or (iii) the entity's
equity neither absorbs losses or benefits from gains. Meridian owns no interests
in variable interest entities, and therefore this new interpretation has not
affected the Company's consolidated financial statements.
In May 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of this statement did
not have a material effect on the Company's financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes the standards on how companies classify and measure certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. This statement did not have any
significant impact on the Company's consolidated financial statements.
11. SUBSEQUENT EVENT
In August 2004, the Company completed a public offering of 13,800,000 shares of
common stock at a price of $7.25 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $95.6 million.
The Company repurchased all of the 7,082,030 shares of its common stock that
were beneficially owned by Shell Oil Company for $49.3 million and a portion of
the remaining proceeds of this equity offering will be used to repay borrowings
under its senior secured credit agreement, which will increase funds available
to the Company to accelerate planned capital expenditures for drilling
activities and related pipeline construction.
17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a discussion of The Meridian Resource Corporation and its
subsidiaries ("Meridian" or the "Company") financial operations for the three
and six months ended June 30, 2004 and 2003. The Company's consolidated
financial statements included in this report, as well as our Annual Report on
Form 10-K for the year ended December 31, 2003 (and the notes attached thereto),
should be read in conjunction with this discussion.
GENERAL.
BUSINESS ACTIVITIES. During the first six months of 2004, Meridian's exploration
activities have been focused primarily in the Company's Biloxi Marshlands and
Weeks Island project areas. As a result of these and similar operations during
the last twelve months, the average daily production for the first six months of
2004 increased by 52% to 96.7 Mmcfe compared to an average daily rate of 64.1
Mmcfe for the first half of 2003. As a result of this and an increase in oil and
natural gas prices, the Company's revenues for the first six months increased in
excess of 64% when compared to the same period last year, cash flows from
operations increased in excess of 110% for the same period and net earnings
increased over 124%. With the recent completion of the southern extension of our
Biloxi pipeline, the Ducros et al No. 32-1 well and the BML 22/SL 17980 No. 1
well were placed on production at a gross rate of 19.0 Mmcfe/d (12.5 Mmcfe/d
net), bringing the Company's current daily production to a net range of 105
Mmcfe to 110 Mmcfe.
In July, 2004, the Biloxi Marshlands ("BML") No. 7-2 well at the South Atlas
prospect area was tested through ten feet of perforations at a stabilized gross
daily flow rate of 13.3 Mmcf/d through a 30/64-inch choke. Flowing tubing
pressure was measured at 3,134 psi and shut-in tubing pressure was measured at
3,688 psi. We mobilized the drilling rig from the BML No. 7-2 location to the
BML No. 7-3 location on the Pluto prospect. The BML No. 7-3 has tested through
34 feet of perforations at a stabilized gross daily flow rate of 8.8 Mmcf/d
through a 22/64-inch choke. Flowing tubing pressure was measured at 2,994 psi
and shut-in tubing pressure was measured at 3,635 psi. When the completion
facilities on these two wells are completed by mid-August 2004, they will be
placed on production. The combined test results from these two wells totaled a
gross rate of 22.1 Mmcf/d, which will significantly increase our current daily
net production rate. We hold a 92% working interest in both of these wells.
Total capital expenditures for the first six months of 2004 approximated $59.6
million. Since the beginning of the year, the Company has drilled eight
successful wells in the Biloxi Marshlands and Weeks Island project areas. In
addition to the drilling activities, Meridian extended its proprietary 3-D data
base at Biloxi Marshlands with the shooting of 264 square miles of new data, the
total of which ultimately will provide approximately 540 square miles covering
approximately 400,000 acres in St. Bernard Parish, Louisiana. We are presently
processing the data and will begin interpretation in the next 60 days. It is
anticipated that the Biloxi Marshlands project area will comprise a substantial
portion of the Company's future drilling inventory over the next several years
as it continues to work the entire 3-D data set ranging in depths from the
shallow Deltaic sand formations to the deep Cretaceous sand formations for new
prospect opportunities. The Company has announced that it intends to increase
its capital budget to approximately $110 million for 2004 or 45% over its 2003
spending, subject to adjustments depending on drilling results, oil and natural
gas prices and other factors. We have scheduled 15 to 20 wells to be drilled in
Biloxi during 2004 and plan to drill about two wells per month for the remainder
of the year and into 2005. In addition, we currently plan to drill up to 12
additional wells in other areas during 2004. These include five wells at Weeks
Island, up to three wells at Riceville, up to three wells at Turtle Bayou and
one well at Ramos.
18
During July 2004, drilling operations began on the Hosemann #1 well on the
Enterprise prospect. The well is being drilled to a proposed total depth of
18,500 feet and is currently drilling at 11,600 feet. We are non-operator of the
well and after payout of the drilling costs our working interest is
approximately 30%. Also during July, 2004, the Company began drilling the CL&F
A-2 well on the North Turtle Bayou prospect. The well is an updip location to a
well that encountered mechanical problems. The well will be drilled to a total
depth of approximately 15,400 feet and is currently drilling at 7,700 feet. The
Company holds a 96.5% working interest in the well.
In the Weeks Island field, we are drilling our Goodrich Cocke #10 well on the
Camille prospect. The well is being drilled to a total depth of approximately
11,700 feet measured depth and is currently at approximately 10,000 feet. We
hold a 97% working interest in this well.
INDUSTRY CONDITIONS. Revenues, profitability and future growth rates of Meridian
are substantially dependent upon prevailing prices for oil and natural gas. Oil
and natural gas prices have been extremely volatile in recent years and are
affected by many factors outside of our control. Our average oil price (after
adjustments for hedging activities) for the three months ended June 30, 2004,
was $27.36 per barrel compared to $25.19 per barrel for the three months ended
June 30, 2003, and $25.10 per barrel for the three months ended March 31, 2004.
Our average oil price (after hedges) for the six months ended June 30, 2004, was
$26.29 per barrel compared to $25.17 per barrel for the six months ended June
30, 2003. Our average natural gas price (after adjustments for hedging
activities) for the three months ended June 30, 2004, was $5.86 per Mcf compared
to $5.39 per Mcf for the three months ended June 30, 2003, and $5.70 per Mcf for
the three months ended March 31, 2004. Our average natural gas price (after
hedges) for the six months ended June 30, 2004, was $5.78 per Mcf compared to
$5.59 per Mcf for the six months ended June 30, 2003. Fluctuations in prevailing
prices for oil and natural gas have several important consequences to us,
including affecting the level of cash flow received from our producing
properties, the timing of exploration of certain prospects and our access to
capital markets, which could impact our revenues, profitability and ability to
maintain or increase our exploration and development program.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES. The Company's discussion and
analysis of its financial condition and results of operation are based upon
consolidated financial statements, which have been prepared in accordance with
accounting principles generally accepted and adopted in the United States. The
preparation of these financial statements requires the Company to make estimates
and judgments that affect the reported amounts of assets, liabilities, revenues
and expenses. See the Company's Annual Report on Form 10-K for the year ended
December 31, 2003, for further discussion.
19
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2004 COMPARED TO THREE MONTHS ENDED JUNE 30, 2003
OPERATING REVENUES. Second quarter 2004 oil and natural gas revenues increased
$20.5 million (69%) as compared to second quarter 2003 revenues due to a 51%
increase in production volumes primarily from the Company's previously announced
drilling results in the Biloxi Marshlands ("BML") project area and Weeks Island
coupled with successful workover operations in the Company's Ramos and Weeks
Island fields, offset by natural production declines and property sales.
Further, revenues were enhanced by a 12% increase in average commodity prices on
a natural gas equivalent basis. The drilling and workover success increased our
average daily production from 65 Mmcfe during the second quarter of 2003 to 99
Mmcfe for the second quarter of 2004. Oil and natural gas production volume
totaled 9,002 Mmcfe for the second quarter of 2004, compared to 5,951 Mmcfe for
the comparable period of 2003. With the recent completion of the southern
extension of our Biloxi pipeline, the Ducros et al No. 32-1 well and the BML
22/SL 17980 No. 1 well were placed on production at a gross rate of 19.0 Mmcfe/d
(12.5 Mmcfe/d net). Current production is ranging between 105 Mmcfe and 110
Mmcfe per day and does not include the most recently announced BML No. 7-2 and
7-3 wells. These two wells are currently scheduled to be placed on production by
mid-August 2004.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended June 30, 2004 and
2003:
THREE MONTHS ENDED
JUNE 30, INCREASE
2004 2003 (DECREASE)
---- ---- ----------
Production Volumes:
Oil (Mbbl) 346 347 --%
Natural gas (MMcf) 6,927 3,869 79%
Mmcfe 9,002 5,951 51%
Average Sales Prices:
Oil (per Bbl) $ 27.36 $ 25.19 9%
Natural gas (per Mcf) $ 5.86 $ 5.39 9%
Mmcfe $ 5.56 $ 4.97 12%
Operating Revenues (000's):
Oil $ 9,467 $ 8,742 8%
Natural gas 40,598 20,861 95%
------- ------- -----
Total Operating Revenues $50,065 $29,603 69%
======= ======= =====
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
decreased $0.1 million (2%) to $2.7 million during the second quarter of 2004,
compared to $2.8 million in 2003. However, on a unit basis, lease operating
expenses decreased $0.16 per Mcfe to $0.31 per Mcfe for the second quarter of
2004 from $0.47 per Mcfe for the second quarter of 2003. Oil and gas operating
expenses include additional operating expenses associated with the Biloxi
Marshlands project area, offset by savings resulting from sold properties,
combined with other cost savings.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $1.0
million (62%) to $2.5 million for the second quarter of 2004, compared to $1.5
million during the same period in 2003 primarily because of an increase in
natural gas production and a higher natural gas tax rate. Meridian's oil and
natural gas production is primarily from Louisiana, and is therefore subject to
Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of
gross oil revenues and $0.171 per Mcf for natural gas for the
20
first six months of 2004, an increase from $0.122 per Mcf for the first half of
2003. The Company's increase was primarily due to the increase in natural gas
production and the increase in the natural gas tax rate. On an equivalent unit
of production basis, severance and ad valorem taxes increased to $0.28 per Mcfe
from $0.26 per Mcfe for the comparable three-month period. Beginning July 1,
2004, the revised severance tax rate for natural gas production in Louisiana
over the next twelve months will be $0.208 per Mcf. This will significantly
increase the amount of severance taxes being paid in future periods
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $10.2
million (68%) during the second quarter of 2004 to $25.4 million, from $15.2
million for the same period of 2003. This was primarily the result of the 51%
increase in production volumes in 2004 over 2003 levels, and an increase in the
depletion rate as compared to the 2003 period. On a unit basis, depletion and
depreciation expense increased by $0.27 per Mcfe, to $2.82 per Mcfe for the
three months ended June 30, 2004, compared to $2.55 per Mcfe for the same period
in 2003.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$0.5 million to $3.5 million compared to $3.0 million for 2003. On an equivalent
unit of production basis, general and administrative expenses decreased $0.11
per Mcfe to $0.39 per Mcfe for the second quarter of 2004 compared to $0.50 per
Mcfe for the comparable 2003 period.
INTEREST EXPENSE. Interest expense decreased $1.7 million (48%), to $1.8 million
for the second quarter of 2004 in comparison to the second quarter of 2003. The
decrease is primarily a result of reduction in long-term debt. With the
conversion of the $20 million convertible subordinated notes into common stock
and the second quarter 2004 repayments of $8.0 million of debt, the Company will
realize additional future savings in interest. With the completion of the
recently announced stock offering, the Company anticipates that it will utilize
the funds to reduce the outstanding debt by an additional $40-45 million in
August 2004, which will significantly lower interest expense in future periods.
SIX MONTHS ENDED JUNE 30, 2004 COMPARED TO SIX MONTHS ENDED JUNE 30, 2003
OPERATING REVENUES. Oil and natural gas revenues during the six months ended
June 30 2004, increased $37.6 million (64%) as compared to first half 2003
revenues due to a 52% increase in production volumes primarily from the
Company's previously announced drilling results in the Biloxi Marshlands ("BML")
project area and Weeks Island coupled with successful workover operations in the
Company's Ramos and Weeks Island fields, offset by natural production declines
and property sales. Further, revenues were enhanced by an 8% increase in average
commodity prices on a natural gas equivalent basis. The drilling and workover
success increased our average daily production from 64 Mmcfe during the first
six months of 2003 to 97 Mmcfe for the first six months of 2004. Oil and natural
gas production volume totaled 17,598 Mmcfe for the first six months of 2004,
compared to 11, 597 Mmcfe for the comparable period of 2003. With the recent
completion of the southern extension of our Biloxi pipeline, the Ducros et al
No. 32-1 well and the BML 22/SL 17980 No. 1 well were placed on production at a
gross rate of 19.0 Mmcfe/d (12.5 Mmcfe/d net), bringing the Company's current
daily production to a net range of 105 Mmcfe to 110 Mmcfe. Within the next 15
days, the production facilities will be completed for the BML No. 7-2 and the
BML No. 7-3 wells. These two additional wells being placed on production will
significantly increase our current average daily production rate.
21
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the six months ended June 30, 2004 and
2003:
SIX MONTHS ENDED
JUNE 30, INCREASE
2004 2003 (DECREASE)
---- ---- ----------
Production Volumes:
Oil (Mbbl) 657 744 (12)%
Natural gas (MMcf) 13,656 7,132 91%
Mmcfe 17,598 11,597 52%
Average Sales Prices:
Oil (per Bbl) $ 26.29 $ 25.17 4%
Natural gas (per Mcf) $ 5.78 $ 5.59 3%
Mmcfe $ 5.47 $ 5.05 8%
Operating Revenues (000's):
Oil $17,274 $18,727 (8)%
Natural gas 78,931 39,863 98%
------- -------
Total Operating Revenues $96,205 $58,590 64%
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $0.5 million (9%) to $5.8 million during the first six months of 2004,
compared to $5.3 million in 2003. However, on a unit basis, lease operating
expenses decreased $0.13 per Mcfe to $0.33 per Mcfe for the first six months of
2004 from $0.46 per Mcfe for the first half of 2003. Oil and gas operating
expenses include additional operating expenses associated with the Biloxi
Marshlands project area, offset by savings resulting from sold properties,
combined with other cost savings.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $1.4
million (43%) to $4.8 million for the first six months of 2004, compared to $3.4
million during the same period in 2003 primarily because of an increase in
natural gas production and a higher natural gas tax rate. Meridian's oil and
natural gas production is primarily from Louisiana, and is therefore subject to
Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of
gross oil revenues and $0.171 per Mcf for natural gas for the first six months
of 2004, an increase from $0.122 per Mcf for the first half of 2003. The
Company's increase was primarily due to the increase in natural gas production
and the increase in the natural gas tax rate. On an equivalent unit of
production basis, severance and ad valorem taxes decreased to $0.27 per Mcfe
from $0.29 per Mcfe for the comparable six-month period, reflecting a shift in
the mix between oil and natural gas production. Beginning July 1, 2004, the
revised severance tax rate for natural gas production in Louisiana over the next
twelve months will be $0.208 per Mcf. This will significantly increase the
amount of severance taxes being paid in future periods.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $19.3
million (65%) during the first half of 2004 to $49.1 million, from $29.8 million
for the same period of 2003. This was primarily the result of the 52% increase
in production volumes in 2004 over 2003 levels, and an increase in the depletion
rate as compared to the 2003 period. On a unit basis, depletion and depreciation
expense increased by $0.22 per Mcfe, to $2.79 per Mcfe for the six months ended
June 30, 2004, compared to $2.57 per Mcfe for the same period in 2003.
22
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$0.9 million to $6.7 million compared to $5.8 million for 2003. On an equivalent
unit of production basis, general and administrative expenses decreased $0.12
per Mcfe to $0.38 per Mcfe for the first six months of 2004 compared to $0.50
per Mcfe for the comparable 2003 period.
INTEREST EXPENSE. Interest expense decreased $1.9 million (33%), to $4.0 million
for the first six months of 2004 in comparison to the first half of 2003. The
decrease is primarily a result of reduction in long-term debt. With the
conversion of the $20 million convertible subordinated notes into common stock
and the 2004 repayments of $13.3 million of debt, the Company will realize
additional future savings in interest. With the completion of the recently
announced stock offering, the Company anticipates that it will utilize the funds
to reduce the outstanding debt by an additional $40-45 million in August 2004,
which will significantly lower interest expense in future periods.
ADOPTION OF STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 143. On January 1,
2003, the Company adopted Statement of Financial Accounting Standards No. 143
("SFAS No. 143"), "Accounting for Asset Retirement Obligations." As a result,
the Company recorded a long-term liability of $4.5 million representing the
discounted present value of the estimated retirement obligations and an increase
in capitalized oil and gas properties of $3.2 million. The liability will be
accreted to its future value in subsequent reporting periods and will be charged
to earnings on the Company's Consolidated Statement of Operations as "Accretion
Expense." As a result of adoption of SFAS No. 143, the Company has charged
approximately $0.3 million to earnings as accretion expense during the 2004 and
2003 periods. The cumulative effect of the change in accounting principle for
prior years totaled $1.3 million, or $0.03 per share, and was charged to
earnings in the first quarter of 2003.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first six months of 2004, Meridian's capital
expenditures were internally financed with cash from operations. As of June 30,
2004, the Company had a cash balance of $11.8 million and a working capital
deficit of $13.9 million. This deficit was made up primarily of $5.0 million of
current maturities of long-term debt, and a $12.3 million net current liability
associated with price risk management activities which will be offset by future
revenues. As of June 30, 2004, the Company had unutilized borrowing capacity of
$13.5 million from our credit facility. With the completion of our recently
announced stock offering, the Company anticipates that it will reduce our
outstanding debt by a range of $40 million to $45 million during August 2004.
This repayment will increase our unutilized borrowing capacity by $35 million to
$40 million and significantly lower the amount of interest to be paid in future
periods.
CASH FLOWS. Net cash provided by operating activities was $74.3 million for the
six months ended June 30, 2004, as compared to $35.4 million for the same period
in 2003. The increase of $38.9 million was primarily due to the increase in
revenues from oil and natural gas of $37.6 million in the first six months of
2004, over the first six months of 2003.
Net cash used in investing activities was $59.7 million during the six months
ended June 30, 2004, versus $31.6 million in the first six months of 2003. The
increase in capital expenditures of $27.9 million was primarily associated with
the acquisition of the Company's new 264-square mile 3-D survey at the Biloxi
Marshlands project area, coupled with expenditures for drilling and related
activities.
Cash flows used in financing activities during the first six months of 2004 were
$15.6 million, compared to cash used in financing activities of $0.9 million
during the first six months of 2003. This additional cash used in financing
activities was primarily due to $3.9 million paid in preferred stock dividends
coupled with the debt repayments of $13.3 million. With the preferred stock
conversion of approximately $28 million in the first six months of 2004, the
Company will see an annualized $2.0 million reduction of dividend payments.
23
CREDIT FACILITY. During August 2002, the Company replaced its Chase Manhattan
Bank Credit Facility with a new three-year $175 million underwritten senior
secured credit agreement (the "Credit Agreement") with Societe Generale as
administrative agent, lead arranger and book runner, and Fortis Capital
Corporation, as co-lead arranger and documentation agent. Borrowings under the
Credit Agreement mature on August 13, 2005. The borrowing base is currently set
at $127.5 million effective on July 31, 2004. Credit Facility payments of $8.3
million have been made during the first six months of 2004, bringing the
outstanding balance to $114 million as of June 30, 2004. The Company has made
additional debt repayments of $40 million in August 2004, which brings our
unutilized borrowing capacity to $53.5 million.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders or borrower, under the Credit Agreement, have the right to redetermine
the borrowing base at any time, once during each calendar year. Borrowings under
the Credit Agreement are secured by pledges of outstanding capital stock of the
Company's subsidiaries and a mortgage on the Company's oil and natural gas
properties of at least 90% of its present value of proved properties. The Credit
Agreement contains various restrictive covenants, including, among other items,
maintenance of certain financial ratios and restrictions on cash dividends on
Common Stock and under certain circumstances Preferred Stock, and an unqualified
audit report on the Company's consolidated financial statements.
Under the Credit Agreement, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus
0.5%, plus an additional 0.5% to 1.5% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At June 30, 2004, the three-month LIBOR interest rate was
1.61%. The Credit Agreement also provides for commitment fees ranging from
0.375% to 0.5% per annum.
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended a short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million on
April 5, 2002, with a maturity date of December 31, 2004. The notes are
unsecured and contain customary events of default, but do not contain any
maintenance or other restrictive covenants. The interest rate is LIBOR plus 5.5%
from January 1, 2003, through August 31, 2003, and LIBOR plus 6.5% from
September 1, 2003, through December 31, 2004. At June 30, 2004, the three-month
LIBOR interest rate was 1.61%. A note payment of $5 million was made during
April 2004, with the remaining $5 million payable on December 31, 2004. The
Company is in compliance with the terms of this agreement.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK A private placement of $66.85
million of 8.5% redeemable convertible preferred stock was completed during May
2002. The preferred stock is convertible into shares of the Company's Common
Stock at a conversion price of $4.45 per share. Dividends are payable
semi-annually in cash or additional preferred stock. At the option of the
Company, one-third of the preferred shares can be forced to convert to Common
Stock if the closing price of the Company's Common Stock exceeds 150% of the
conversion price for 30 out of 40 consecutive trading days on the New York Stock
Exchange. The preferred stock is subject to redemption at the option of the
Company after March 2005, and mandatory redemption on March 31, 2009. The
holders of the preferred stock have been granted registration rights with
respect to the shares of Common Stock issued upon conversion of the preferred
stock.
In June 2004, we exercised our right, as described above, to convert one-third
of our remaining issued and outstanding preferred stock into shares of our
Common Stock. The conversion was completed on a pro rata basis and included a
cash payment for accrued and unpaid dividends through the June 8, 2004,
conversion date, at which time dividends ceased to accrue on the converted
shares. Based on this conversion and other
24
voluntary conversions, our outstanding Series C preferred stock has been
reduced from a high stated value of approximately $72.7 million as of June 30,
2003 to approximately $32.4 million as of June 30, 2004, representing a future
cash savings in dividends of approximately $3.4 million on an annualized basis.
OIL AND NATURAL GAS HEDGING ACTIVITIES. The Company may address market risk by
selecting instruments whose value fluctuations correlate strongly with the
underlying commodity being hedged. The Company enters into swaps and other
derivative contracts to hedge the price risks associated with a portion of
anticipated future oil and gas production. These swaps allow the Company to
predict with greater certainty the effective oil and natural gas prices to be
received for our hedged production. While the use of hedging arrangements limits
the downside risk of adverse price movements, it may also limit future gains
from favorable movements. Under these agreements, payments are received or made
based on the differential between a fixed and a variable product price. These
agreements are settled in cash at or prior to expiration or exchanged for
physical delivery contracts. The Company does not obtain collateral to support
the agreements, but monitors the financial viability of counter-parties and
believes its credit risk is minimal on these transactions. In the event of
nonperformance, the Company would be exposed to price risk. The Company has some
risk of accounting loss since the price received for the product at the actual
physical delivery point may differ from the prevailing price at the delivery
point required for settlement of the hedging transaction.
These swaps have been designated as cash flow hedges as provided by SFAS No. 133
and any changes in fair value of the cash flow hedge resulting from
ineffectiveness of the hedge is reported in the consolidated statement of
operations as revenues.
CAPITAL EXPENDITURES. Total capital expenditures for this period approximated
$59.6 million. Although the Company plans to commence additional drilling during
the remainder of 2004, such operations will depend primarily on achieving
anticipated cash flows, permitting of wells and the availability of suitable
drilling rigs. Meridian recently completed the final field work on its
264-square mile 3-D seismic survey at its Biloxi Marshlands acreage and
preliminary indications are that a number of additional drilling locations are
present in the area encompassing the new survey which will form the basis for
its future drilling activities during 2004 and 2005.
Based on internal projections, using its internal risked analysis of production
based on an expected capital expenditures program for 2004 of $110 million, the
Company believes that it can further improve its balance sheet while, at the
same time, continuing its scheduled capital expenditure program, drilling 15 to
20 low-risk wells and acquiring additional 3-D seismic data over its Biloxi
Marshlands project and other exploration areas targeted for exploration growth.
DIVIDENDS. It is our policy to retain existing cash for reinvestment in our
business, and therefore, we do not anticipate that dividends will be paid with
respect to the Common Stock in the foreseeable future. During May 2002, the
Company completed the private placement of $67 million of 8.5% redeemable
convertible preferred stock and dividends are payable semi-annually. A
semi-annual cash dividend of $3.1 million was paid in January 2004. On June 29,
2004, a cash dividend of $0.8 million was paid for converted shares. In July
2004, a semi-annual cash dividend of $1.4 million was paid. Under the terms of
the Credit Agreement, dividend payments required during 2003 on the preferred
stock were paid-in-kind through our issuance of additional preferred stock.
25
FORWARD-LOOKING INFORMATION
From time to time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involve risk and uncertainty. These forward-looking statements may
include, but are not limited to exploration and seismic acquisition plans,
anticipated results from current and future exploration prospects, future
capital expenditure plans and plans to sell properties, anticipated results from
third party disputes and litigation, expectations regarding future financing and
compliance with our credit facility, the anticipated results of wells based on
logging data and production tests, future sales of production, earnings,
margins, production levels and costs, market trends in the oil and natural gas
industry and the exploration and development sector thereof, environmental and
other expenditures and various business trends. Forward-looking statements may
be made by management orally or in writing including, but not limited to, the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section and other sections of our filings with the Securities and
Exchange Commission under the Securities Act of 1933, as amended, and the
Securities Exchange Act of 1934, as amended.
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following:
CHANGES IN THE PRICE OF OIL AND NATURAL GAS. The prices we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that we do not control, including
seasonality, worldwide economic conditions, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other oil-producing countries, the actions of the Organization of
Petroleum Exporting Countries and domestic government regulation, legislation
and policies. Material declines in the prices received for oil and natural gas
could make the actual results differ from those reflected in our forward-looking
statements.
OPERATING RISKS. The occurrence of a significant event against which we are not
fully insured could have a material adverse effect on our financial position and
results of operations. Our operations are subject to all of the risks normally
incident to the exploration for and the production of oil and natural gas,
including uncontrollable flows of oil, natural gas, brine or well fluids into
the environment (including groundwater and shoreline contamination), blowouts,
cratering, mechanical difficulties, fires, explosions, unusual or unexpected
formation pressures, pollution and environmental hazards, each of which could
result in damage to or destruction of oil and natural gas wells, production
facilities or other property, or injury to persons. In addition, we are subject
to other operating and production risks such as title problems, weather
conditions, compliance with government permitting requirements, shortages of or
delays in obtaining equipment, reductions in product prices, limitations in the
market for products, litigation and disputes in the ordinary course of business.
Although we maintain insurance coverage considered to be customary in the
industry, we are not fully insured against certain of these risks either because
such insurance is not available or because of high premium costs. We cannot
predict if or when any such risks could affect our operations. The occurrence of
a significant event for which we are not adequately insured could cause our
actual results to differ from those reflected in our forward-looking statements.
DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit
a prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analysis, production data and engineering
studies, which are inherently imprecise. Therefore, we cannot assure you that
all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause
the actual results to differ from those reflected in our forward-looking
statements.
26
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of those
accumulations of data and of engineering and geological interpretation and
judgment. Reserve estimates are inherently imprecise and may be expected to
change as additional information becomes available. There are numerous
uncertainties inherent in estimating quantities and values of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond our control. Because all reserve
estimates are to some degree speculative, the quantities of oil and natural gas
that we ultimately recover, production and operating costs, the amount and
timing of future development expenditures and future oil and natural gas sales
prices may differ from those assumed in these estimates. Significant downward
revisions to our existing reserve estimates could cause the actual results to
differ from those reflected in our forward-looking statements.
BORROWING BASE FOR THE CREDIT FACILITY. The Credit Agreement with Societe
Generale and Fortis Capital Corporation is presently scheduled for borrowing
base redetermination dates on a quarterly basis with the next such
redetermination scheduled for October 31, 2004. The borrowing base is
redetermined on numerous factors including current reserve estimates, reserves
that have recently been added, current commodity prices, current production
rates and estimated future net cash flows. These factors have associated risks
with each of them. Significant reductions or increases in the borrowing base
will be determined by these factors, which, to a significant extent, are not
under the Company's control.
27
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is currently exposed to market risk from hedging contracts changes
and changes in interest rates. A discussion of the market risk exposure in
financial instruments follows.
INTEREST RATES
We are subject to interest rate risk on our long-term fixed interest rate debt
and variable interest rate borrowings. Our long-term borrowings primarily
consist of borrowings under the Credit Facility and principal due December 31,
2004 under our Subordinated Credit Agreement. Since interest charged borrowings
under the Credit Facility floats with prevailing interest rates (except for the
applicable interest period for Eurodollar loans), the carrying value of
borrowings under the Credit Facility should approximate the fair market value of
such debt. Changes in interest rates, however, will change the cost of
borrowing. Assuming $114.0 million remains borrowed under the Credit Facility
and $5 million remains borrowed under the Subordinated Credit Agreement, we
estimate our annual interest expense will change by $1.14 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Facility and $5 million from the Subordinated Credit Agreement. Changes in
interest rates would, assuming all other things being equal, cause the fair
market value of debt with a fixed interest rate, such as the Notes, to increase
or decrease, and thus increase or decrease the amount required to refinance the
debt. The fair value of the Notes is dependent on prevailing interest rates.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter into swaps and other derivative contracts to hedge
the price risks associated with a portion of anticipated future oil and natural
gas production. While the use of hedging arrangements limits the downside risk
of adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. Meridian does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, the Company
would be exposed to price risk. Meridian has some risk of accounting loss since
the price received for the product at the actual physical delivery point may
differ from the prevailing price at the delivery point required for settlement
of the hedging transaction.
In 2002, we entered into certain swap agreements as summarized in the table
below. The Notional Amount is equal to the total net volumetric hedge position
of the Company during the periods presented. The positions effectively hedge
approximately 9% of our proved developed natural gas production and 62% of our
proved developed oil production during the respective terms of the swap
agreements. The fair values of the hedges are based on the difference between
the strike price and the New York Mercantile Exchange future prices for the
applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at June 30, 2004
Amount ($ per unit) (in thousands)
------ ------------ --------------
Natural Gas (mmbtu)
July 2004 - June 2005 2,230,000 $ 3.73 $ (5,622)
Oil (bbls)
July 2004 - July 2005 588,000 $ 23.38 (7,438)
----------
$ (13,060)
----------
28
ITEM 4. CONTROLS AND PROCEDURES
We conducted an evaluation under the supervision and with the participation of
Meridian's management, including our Chief Executive Officer and Chief
Accounting Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-15(e) under the
Securities Exchange Act of 1934) as of the end of the second quarter of 2004.
Based upon that evaluation, our Chief Executive Officer and Chief Accounting
Officer concluded that the design and operation of our disclosure controls and
procedures are effective. There have been no significant changes in our internal
controls or in other factors during the second quarter of 2004 that could
significantly affect these controls.
29
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
ENVIRONMENTAL LITIGATION. Various landowners have filed claims against Meridian
(along with numerous other oil companies) in four similar lawsuits concerning
the Weeks Island, Gibson, Bayou Pigeon and Napoleonville Fields. The lawsuits
seek injunctive relief and other relief, including unspecified amounts in both
actual and punitive damages for alleged breaches of mineral leases and alleged
failure to restore the plaintiffs' lands from alleged contamination and
otherwise from the defendants' oil and gas operations.
There are no other material legal proceedings which exceeds our insurance limits
to which Meridian or any of its subsidiaries is a party or to which any of its
property is subject, other than ordinary and routine litigation incidental to
the business of producing and exploring for crude oil and natural gas.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits
1.1 Underwriting Agreement, dated July 28, 2004, between Friedman,
Billings, Ramsey & Co. Inc., as Representative of the several
Underwriters, and The Meridian Resource Corporation
(incorporated by reference to Exhibit 1.1 of the Company's
Current Report on Form 8-K dated August 4, 2004).
10.1 Stock Purchase Agreement, dated July 21, 2004, between The
Meridian Resource Corporation and SWEPI, LP, a Delaware
limited partnership (incorporated by reference to Exhibit 10.1
of the Company's Current Report on Form 8-K dated August 4,
2004).
31.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act
of 1934, as amended.
31.2 Certification of President pursuant to Rule 13a-14(a) or Rule
15d-14(a) under the Securities Exchange Act of 1934, as
amended.
31.3 Certification of Chief Accounting Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act
of 1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act
of 1934, as amended, and 18 U.S.C. Section 1350.
32.2 Certification of President pursuant to Rule 13a-14(b) or Rule
15d-14(b) under the Securities Exchange Act of 1934, as
amended, and 18 U.S.C. Section 1350.
32.3 Certification of Chief Accounting Officer pursuant Rule
13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act
of 1934, as amended, and 18 U.S.C. Section 1350.
(b) Reports on Form 8-K.
None.
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.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
(Registrant)
Date: August 9, 2004 By: /s/ Lloyd V. DeLano
-------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
31
EXHIBIT INDEX
Exhibit No. Description of Exhibit
1.1 Underwriting Agreement, dated July 28, 2004, between Friedman,
Billings, Ramsey & Co. Inc., as Representative of the several
Underwriters, and The Meridian Resource Corporation
(incorporated by reference to Exhibit 1.1 of the Company's
Current Report on Form 8-K dated August 4, 2004).
10.1 Stock Purchase Agreement, dated July 21, 2004, between The
Meridian Resource Corporation and SWEPI, LP, a Delaware limited
partnership (incorporated by reference to Exhibit 10.1 of the
Company's Current Report on Form 8-K dated August 4, 2004).
31.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of
1934, as amended.
31.2 Certification of President pursuant to Rule 13a-14(a) or Rule
15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.3 Certification of Chief Accounting Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of
1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to Rule
13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of
1934, as amended, and 18 U.S.C. Section 1350.
32.2 Certification of President pursuant to Rule 13a-14(b) or Rule
15d-14(b) under the Securities Exchange Act of 1934, as amended,
and 18 U.S.C. Section 1350.
32.3 Certification of Chief Accounting Officer pursuant Rule
13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of
1934, as amended, and 18 U.S.C. Section 1350.