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: September 30, 2003
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 November 7, 2003 58,982,068
Page 1 of 35
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 Nine Months Ended September 30, 2003 and 2002 3
Consolidated Balance Sheets as of September 30, 2003 (unaudited)
and December 31, 2002 4
Consolidated Statements of Cash Flows (unaudited) for the
Nine Months Ended September 30, 2003 and 2002 6
Consolidated Statements of Changes in Stockholders' Equity (unaudited) for the
Nine Months Ended September 30, 2003 and 2002 7
Notes to Consolidated Financial Statements (unaudited) 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 3. Quantitative and Qualitative Disclosures about Market Risk 25
Item 4. Controls and Procedures 26
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 27
Item 4. Submission of Matters to a Vote of Security Holders 27
Item 6. Exhibits and Reports on Form 8-K 28
SIGNATURES 29
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands of dollars, except per share information)
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- --------------------
2003 2002 2003 2002
------- -------- ------- --------
REVENUES:
Oil and natural gas $39,129 $ 26,445 $97,719 $ 82,715
Price risk management activities - 222 - 87
Interest and other 208 108 297 294
------- -------- ------- --------
39,337 26,775 98,016 83,096
------- -------- ------- --------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 2,714 2,720 8,001 8,822
Severance and ad valorem taxes 2,025 1,519 5,392 6,636
Depletion and depreciation 22,497 19,262 52,339 46,181
Accretion expense 145 - 401 -
General and administrative 2,880 2,862 8,662 9,104
Impairment of long-lived assets - 69,124 - 69,124
------- -------- ------- --------
30,261 95,487 74,795 139,867
------- -------- ------- --------
EARNINGS (LOSS) BEFORE INTEREST AND INCOME TAXES 9,076 (68,712) 23,221 (56,771)
------- -------- ------- --------
OTHER EXPENSES:
Interest expense 2,811 3,708 8,755 11,312
Credit facility retirement costs - 1,202 - 1,202
------- -------- ------- --------
EARNINGS (LOSS) BEFORE INCOME TAXES 6,265 (73,622) 14,466 (69,285)
------- -------- ------- --------
INCOME TAXES
Current (490) - (490) 100
Deferred 2,100 (23,800) 2,100 (22,300)
------- -------- ------- --------
1,610 (23,800) 1,610 (22,200)
------- -------- ------- --------
EARNINGS (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE: 4,655 (49,822) 12,856 (47,085)
Cumulative effect of change in accounting principle - - (1,309) -
------- -------- ------- --------
NET EARNINGS (LOSS): 4,655 (49,822) 11,547 (47,085)
Dividends on preferred stock 1,690 1,562 4,937 2,704
------- -------- ------- --------
NET EARNINGS (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS $ 2,965 $(51,384) $ 6,610 $(49,789)
======= ======== ======= ========
NET EARNINGS (LOSS) PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
Basic $ 0.06 $ (1.03) $ 0.16 $ (1.00)
Diluted $ 0.05 $ (1.03) $ 0.15 $ (1.00)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
ACCOUNTING PRINCIPLE PER SHARE:
Basic and Diluted $ - $ - $ (0.03) $ -
------- -------- ------- --------
NET EARNINGS (LOSS) PER SHARE:
Basic $ 0.06 $ (1.03) $ 0.13 $ (1.00)
======= ======== ======= ========
Diluted $ 0.05 $ (1.03) $ 0.12 $ (1.00)
======= ======== ======= ========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 53,532 49,946 51,274 49,685
======= ======== ======= ========
Diluted 62,014 49,946 54,764 49,685
======= ======== ======= ========
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 17,599 $ 7,287
Accounts receivable, less allowance for doubtful accounts of
$833 [2003 and 2002] 24,312 24,167
Due from affiliates 2,895 1,557
Prepaid expenses and other 3,733 2,221
Assets from price risk management activities 1,209 604
---------- ----------
Total current assets 49,748 35,836
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$30,416 [2003] and $18,993 [2002] not
subject to depletion) 1,217,781 1,162,436
Land 478 478
Equipment and other 9,807 9,913
---------- ----------
1,228,066 1,172,827
Less accumulated depletion and depreciation 814,132 761,854
---------- ----------
Total property and equipment, net 413,934 410,973
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 133 292
Deferred tax asset 2,994 2,560
Other 5,039 6,579
---------- ----------
Total other assets 8,166 9,431
---------- ----------
Total assets $ 471,848 $ 456,240
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
2003 2002
------------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 10,556 $ 16,842
Revenues and royalties payable 15,477 12,378
Notes payable 930 831
Accrued liabilities 13,527 9,958
Liabilities from price risk management activities 7,191 6,781
Current income taxes payable 441 931
Current portion long-term debt 5,000 35,250
--------- ---------
Total current liabilities 53,122 82,971
--------- ---------
LONG-TERM DEBT 143,320 148,500
--------- ---------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 20,000
--------- ---------
--------- ---------
DEFERRED INCOME TAXES 2,100 -
--------- ---------
OTHER:
Liabilities from price risk management activities 2,705 1,686
Abandonment costs 4,086 -
--------- ---------
6,791 1,686
--------- ---------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
726,500 [2003] and 696,900 [2002] shares of Series C
Redeemable Convertible Preferred Stock issued at stated value) 72,650 69,690
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
58,965,638 [2003] and 53,868,343 [2002] issued) 616 557
Additional paid-in capital 382,467 378,215
Accumulated deficit (203,128) (209,738)
Accumulated other comprehensive loss (5,744) (4,938)
Unamortized deferred compensation (346) (356)
--------- ---------
173,865 163,740
Less treasury stock, at cost (3,779,225 [2002] shares) - 30,347
--------- ---------
Total stockholders' equity 173,865 133,393
--------- ---------
Total liabilities and stockholders' equity $ 471,848 $ 456,240
========= =========
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
NINE MONTHS ENDED
SEPTEMBER 30,
---------------------
2003 2002
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 11,547 $(47,085)
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Cumulative effect of change in accounting principle 1,309 -
Depletion and depreciation 52,339 46,181
Amortization of other assets 1,280 1,606
Credit facility retirement costs - 1,202
Non-cash compensation 1,063 1,246
Non-cash price risk management activities - (87)
Accretion expense 401 -
Impairment of long-lived assets - 69,124
Deferred income taxes 2,100 (22,300)
Changes in assets and liabilities:
Accounts receivable (145) 198
Due from affiliates (1,338) (1,186)
Prepaid expenses and other (1,512) (960)
Accounts payable (6,286) (21,007)
Revenues and royalties payable 3,099 1,041
Accrued liabilities and other 1,276 (7,240)
-------- --------
Net cash provided by operating activities 65,133 20,733
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (55,552) (55,685)
Sale of property and equipment 2,628 461
-------- --------
Net cash used in investing activities (52,924) (55,224)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redeemable preferred stock - 66,850
Reductions in long-term debt (35,430) (25,000)
Net proceeds from notes payable 99 257
Issuance of stock/exercise of options 33,605 218
Preferred dividends - (1,102)
Additions to deferred loan costs (171) (6,868)
-------- --------
Net cash provided by (used in) financing activities (1,897) 34,355
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS 10,312 (136)
Cash and cash equivalents at beginning of period 7,287 14,340
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 17,599 $ 14,204
======== ========
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS'
EQUITY NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002 (in
thousands and shares)
Common Stock
-------------- Additional Unamortized
Par Paid-In Accumulated Deferred
Shares Value Capital (Deficit) Compensation
------ ------ ---------- ----------- ------------
Balance, December 31, 2001 47,974 $ 553 $393,280 $(157,726) $ (386)
Issuance of rights to common stock - 3 1,240 - (1,242)
Company's 401(k) plan contribution 74 - (375) - -
Issuance of shares as compensation 1,941 - (15,586) - -
Fractional share adjustments 2 - - - -
Compensation expense - - - - 1,246
Accum. other comprehensive loss - - - - -
Preferred dividends - - - (2,704) -
Net (loss) - - - (47,085) -
------ ------ -------- --------- -------
Balance, September 30, 2002 49,991 $ 556 $378,559 $(207,515) $ (382)
====== ====== ======== ========= =======
Balance, December 31, 2002 50,089 $ 557 $378,215 $(209,738) $ (356)
Issuance of rights to common stock - 8 1,045 - (1,053)
Company's 401(k) plan contribution 93 - (569) - -
Exercise of stock options 80 1 78 - -
Compensation expense - - - - 1,063
Issuance of shares from stock offering 8,704 50 3,698 - -
Accum. other comprehensive loss - - - - -
Preferred dividends - - - (4,937) -
Net earnings - - - 11,547 -
------ ------ -------- --------- -------
Balance, September 30, 2003 58,966 $ 616 $382,467 $(203,128) $ (346)
====== ====== ======== ========= =======
Accumulated
Other Treasury Stock
Comprehensive ----------------
Loss Shares Cost Total
------------- ------ -------- --------
Balance, December 31, 2001 $ (185) 5,892 $(47,315) $188,221
Issuance of rights to common stock - - - 1
Company's 401(k) plan contribution - (74) 593 218
Issuance of shares as compensation - (1,941) 15,586 -
Fractional share adjustments - - - -
Compensation expense - - - 1,246
Accum. other comprehensive loss (4,003) - - (4,003)
Preferred dividends - - - (2,704)
Net (loss) - - - (47,085)
------- ----- -------- --------
Balance, September 30, 2002 $(4,188) 3,877 $(31,136) $135,894
======= ===== ======== ========
Balance, December 31, 2002 $(4,938) 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 - (22) 177 256
Compensation expense - - - 1,063
Issuance of shares from stock offering - (3,664) 29,423 33,171
Accum. other comprehensive loss (806) - - (806)
Preferred dividends - - - (4,937)
Net earnings - - - 11,547
------- ----- -------- --------
Balance, September 30, 2003 $(5,744) - $ - $173,865
======= ===== ======== ========
See notes to consolidated financial statements.
7
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, 2002, as filed with the Securities and Exchange Commission.
The financial statements included herein as of September 30, 2003, and for the
three and nine month periods ended September 30, 2003 and 2002, are unaudited,
and in the opinion of management, the information furnished reflects all
material adjustments, consisting of normal recurring adjustments, necessary for
a fair statement 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 $138.5 million and is scheduled to be redetermined and be effective on
January 31, 2004. Credit Facility payments of $26.7 million have been made
during the first nine months of 2003, bringing the outstanding balance to $138.3
million as of September 30, 2003. In October 2003, the Company made $8.0 million
in debt repayments and anticipates that it will continue to make 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 beginning with
those as of and for the year ended December 31, 2002. The Company has received
from the senior lenders a waiver of the covenant that would have triggered an
event of default as a result of the independent auditors' report which contained
a "going concern" modification for our 2002 consolidated financial statements.
Under the Credit Agreement, the Company may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate, 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 a federal funds-based rate plus 1/2 of 1% 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. The Credit Agreement also provides for commitment fees
ranging from 0.375% to 0.5% per annum.
8
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 4.5%
through December 31, 2002, 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.
A note payment of $5 million is due on April 30, 2004, with the remaining $5
million payable on December 31, 2004. Note payments totaling $8.75 million have
been paid in 2003, bringing the outstanding balance to $10.0 million as of
September 30, 2003. The Company is in compliance with the terms of this
agreement.
3. REDEEMABLE PREFERRED STOCK
The redeemable preferred stock has a common stock conversion feature that
provided for a conversion price of $4.75 per share of common stock. It further
provides that if the Company sells common stock at a price less than $4.16 per
share, the conversion price is redetermined to a price of 115% of the actual
consideration received per share of common stock. As a result of sale of common
stock at a price of $3.87 per share, as described in Note 4, the conversion
price on the preferred stock was reduced to $4.45 per share.
4. COMMITMENTS AND CONTINGENCIES
LITIGATION.
VERITAS LAWSUIT. On October 29, 2002, Veritas DGC Land Inc. ("Veritas Land")
filed a complaint against Meridian. The dispute concerns a contract for seismic
services for Meridian's Biloxi Marshlands project in St. Bernard Parish,
Louisiana. Meridian asserted a counterclaim. Purporting to invoke force majeure,
Veritas Land, together with Veritas DGC Inc. (collectively, "Veritas"),
unilaterally terminated the parties' contract. The main dispute is whether
Veritas had breached the parties' contract before the alleged force majeure
events and/or when it terminated the contract; Meridian has not made any
payments to Veritas under the parties' contract. Veritas' complaint seeks
breach-of-contract damages of approximately $6.8 million together with interest,
costs and attorneys' fees.
A settlement was reached October 31, 2003, calling for Meridian to pay $3.5
million to Veritas over six months, and requiring Veritas to pay its contractors
and release various liens associated with 3-D seismic data for 43 square miles,
which was delivered to us. This settlement has been fully reflected in the
Company's third quarter financial statements.
PETROQUEST LAWSUIT. On December 23, 1999, PetroQuest Energy, Inc. (formerly
known as Optima Energy (U.S.) Corporation) ("PetroQuest") filed a complaint
against Meridian seeking damages "estimat[ed] to exceed several million dollars"
for the Company's alleged gross negligence and willful misconduct under a letter
agreement dated October 6, 1993, between Meridian and PetroQuest and a master
participation agreement and joint operating agreement thereunder with respect to
certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in
Calcasieu Parish and certain agreements between Meridian and Amoco Production
Company ("Amoco"), and for alleged wrongful withholding of funds totaling
$886,153.31, as a result of Meridian's satisfying a prior adverse judgment in
favor of Amoco.
On April 4, 2002, Meridian filed an answer denying PetroQuest's claims and
asserted a counterclaim for declaratory relief that the Company is entitled to
retain the amounts (with all interest thereon) that it has suspended from
disbursement to PetroQuest and for attorneys' fees, courts costs and other
expenses incurred in this lawsuit or in connection with PetroQuest's failure to
timely pay the two invoices from Meridian. On or
9
about April 22, 2002, PetroQuest filed a "Reply and Defenses to Counterclaim,"
generally denying that Meridian is entitled to the relief sought in its
counterclaim. A trial date is set for December 15, 2003.
There are no other material legal proceedings to which Meridian or any of its
subsidiaries or partnerships 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.
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, and the remainder of the proceeds is
being used for exploration activities and for other general corporate purposes.
COMPREHENSIVE INCOME.
STATEMENTS OF COMPREHENSIVE INCOME
(in thousands of dollars)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- ---------------------
2003 2002 2003 2002
------ -------- ------- --------
Net earnings (loss) applicable to
common shareholders $2,965 $(51,384) $ 6,610 $(49,789)
Other comprehensive income, net of tax, for
unrealized losses from hedging activities:
Unrealized holding gains (losses) arising during period 944 (4,003) (9,086) (4,003)
Reclassification adjustments 1,695 - 8,280 -
------ -------- ------- --------
Other comprehensive income 2,639 (4,003) (806) (4,003)
------ -------- ------- --------
Comprehensive income $5,604 $(55,387) $ 5,804 $(53,792)
====== ======== ======= ========
10
6. EARNINGS PER SHARE (in thousands, except per share)
The following tables set forth the computation of basic and diluted net earnings
(loss) per share:
THREE MONTHS ENDED SEPTEMBER 30,
2003 2002
------- --------
Numerator:
Net earnings (loss) applicable to common stockholders $ 2,965 $(51,384)
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes 309 N/A
------- --------
Net earnings (loss) applicable to common stockholders
plus assumed conversions $ 3,274 $(51,384)
------- --------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 53,532 49,946
Effect of potentially dilutive common shares:
Warrants 756 N/A
Employee and director stock options 3,726 N/A
Convertible subordinated notes 4,000 N/A
Redeemable preferred stock N/A N/A
------- --------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 62,014 49,946
======= ========
Basic earnings (loss) per share $ 0.06 $ (1.03)
======= ========
Diluted earnings (loss) per share $ 0.05 $ (1.03)
======= ========
NINE MONTHS ENDED SEPTEMBER 30,
2003 2002
------- --------
Numerator:
Net earnings (loss) applicable to common stockholders $ 6,610 $(49,789)
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes N/A N/A
------- --------
Net earnings (loss) applicable to common stockholders
plus assumed conversions $ 6,610 $(49,789)
------- --------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 51,274 49,685
Effect of potentially dilutive common shares:
Warrants 252 N/A
Employee and director stock options 3,238 N/A
Convertible subordinated notes N/A N/A
Redeemable preferred stock N/A N/A
------- --------
Denominator for diluted net earnings per
Share - weighted-average shares outstanding
and assumed conversions 54,764 49,685
======= ========
Basic earnings (loss) per share $ 0.13 $ (1.00)
======= ========
Diluted earnings (loss) per share $ 0.12 $ (1.00)
======= ========
11
7. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company addresses 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.
These swaps have been designated as cash flow hedges as provided by Statement of
Financial Accounting Standards (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 operation as revenues.
The estimated September 30, 2003, fair value of the Company's oil and natural
gas swaps is an unrealized loss of $8.6 million ($5.6 million net of tax)
recognized in other comprehensive income. Based upon September 30, 2003, oil and
natural gas commodity prices, approximately $6.0 million of the loss deferred in
other comprehensive income is expected to lower gross revenues over the next
twelve months when the revenues are generated. The swap agreements expire at
various dates through July 31, 2005.
Payments under these swap agreements reduced oil and natural gas revenues by
$2,608,000 for the three months and $12,739,000 for the nine months ended
September 30, 2003, as a result of hedging transactions.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 11% of our proved developed natural gas production and 77% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at September 30, 2003
Amount ($ per unit) (in thousands)
--------- ---------------- -----------------------
Natural Gas (mmbtu)
October 2003 - June 2005 4,630,000 $ 3.75 $(4,952)
Oil (bbls)
October 2003 - July 2005 1,204,000 $23.81 $(3,601)
------
$(8,553)
-------
12
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. The
compensation expense incurred in the three month and nine month periods ended
September 30, 2003 and 2002, related to restricted stock awards, which totaled
$10 thousand for each quarter, respectively.
The following is a reconciliation of reported earnings (loss) and earnings
(loss) 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 September 30,
2003 2002
------ --------
Net earnings (loss) applicable to common stockholders as reported $2,965 $(51,384)
Stock-based compensation expense determined under
fair value method for all awards, net of tax 10 10
Net earnings (loss) applicable to common stockholders pro forma $2,955 $(51,394)
Basic earnings (loss) per share:
As reported $ 0.06 $ (1.03)
Pro forma $ 0.06 $ (1.03)
Diluted earnings (loss) per share:
As reported $ 0.05 $ (1.03)
Pro forma $ 0.05 $ (1.03)
Nine Months Ended September 30,
2003 2002
------ --------
Net earnings (loss) applicable to common stockholders as reported $6,610 $(49,789)
Stock-based compensation expense determined under
fair value method for all awards, net of tax 30 30
Net earnings (loss) applicable to common stockholders pro forma $6,580 $(49,819)
Basic earnings (loss) per share:
As reported $0.13 $ (1.00)
Pro forma $0.13 $ (1.00)
Diluted earnings (loss) per share:
As reported $0.12 $ (1.00)
Pro forma $0.12 $ (1.00)
13
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 us 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 $401 thousand in the first nine months of 2003.
The pro forma effects 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 September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2003 2002 2003 2002
Net earnings (loss) applicable to
common stockholders $2,965 $(51,384) $6,610 $(49,789)
Additional accretion expense - (117) - (351)
Cumulative effect of accounting change - - 1,309 -
------ ------------------- --------
Pro forma net earnings (loss) $2,965 $(51,501) $7,919 $(50,140)
Pro forma earnings (loss) per share:
Basic $ 0.06 $ (1.03) $ 0.16 $ (1.01)
Diluted $ 0.05 $ (1.03) $ 0.15 $ (1.01)
The following table describes the change in the Company's asset retirement
obligations for the period ended September 30, 2003, and the pro forma amounts
for 2002 (thousands of dollars):
Asset retirement obligation at January 1, 2002 $ 4,053
Accretion expense 470
-------
Asset retirement obligation at December 31, 2002 4,523
Additional retirement obligations recorded in 2003 172
Reduction due to property sale in 2003 (1,010)
Accretion expense 401
-------
Asset retirement obligation at September 30, 2003 $ 4,086
14
10. NEW ACCOUNTING PRONOUNCEMENTS
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. We do not believe that this statement
will have any impact on the Company's consolidated financial statements.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." 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.
142 had no impact on the Company's results of operations.
A reporting issue has arisen regarding the application of certain provisions of
SFAS No. 142 to companies in the extractive industries, including oil and gas
companies. The issue is whether SFAS No. 142 requires registrants to classify
the costs of mineral rights held under lease or other contractual arrangements
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 such mineral rights associated with extracting oil and gas as a component of
oil and gas properties. If it is ultimately determined that SFAS No. 142
requires oil and gas companies to classify costs of mineral rights held under
lease or other contractual arrangement 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 $15.9 million at September 30, 2003, and
$15.8 million at December 31, 2002, respectively, out of oil and gas properties
and into a separate intangible assets line item. 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. 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.
15
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a discussion of Meridian's financial operations for the three
months and nine months ended September 30, 2003 and 2002. The notes to 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, 2002 (and the
notes attached thereto), should be read in conjunction with this discussion.
GENERAL
BUSINESS ACTIVITIES. During the first nine months of 2003, Meridian's
exploration activities have been focused primarily in the Company's Biloxi
Marshlands project area located in St. Bernard Parish, Louisiana and includes
five successful wells during that time period. As a result of our Biloxi
Marshlands drilling results and successful workover operations in the Company's
Ramos field, the average daily production for the third quarter of 2003
increased by 37%, compared to the 2002 exit rate of approximately 65.7 Mmcfe.
Current production is ranging between 90 Mmcfe and 95 Mmcfe per day, and does
not include the most recently announced Biloxi Marshlands No. 18-1 well, which
tested at a daily production rate of approximately 16.5 Mmcfe/d and is expected
to be on production by or immediately after November 15, 2003.
Total capital expenditures for this period approximated $55.6 million. Although
the Company plans to commence additional drilling during the remainder of 2003,
such operations will depend primarily on permitting and the availability of
suitable drilling rigs. Meridian recently completed the final field work on its
187-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.
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 September 30,
2003, was $24.46 per barrel compared to $27.10 per barrel for the three months
ended September 30, 2002, and $25.19 per barrel for the three months ended June
30, 2003. Our average oil price for the nine months ended September 30, 2003,
was $24.95 per barrel compared to $24.06 per barrel for the nine months ended
September 30, 2002. Our average natural gas price (after adjustments for hedging
activities) for the three months ended September 30, 2003, was $4.92 per Mcf
compared to $3.44 per Mcf for the three months ended September 30, 2002, and
$5.39 per Mcf for the three months ended June 30, 2003. Our average natural gas
price for the nine months ended September 30, 2003, was $5.28 per Mcf compared
to $3.18 per Mcf for the nine months ended September 30, 2002. 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, 2002, for further discussion.
16
RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2003 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2002
OPERATING REVENUES. Third quarter 2003 oil and natural gas revenues increased
$12.7 million as compared to third quarter 2002 revenues due to a 24% increase
in production volumes primarily from the Company's previously announced drilling
results in the Biloxi Marshlands project area and successful workover operations
in the Company's Ramos field, offset by natural production declines and property
sales. Further, revenues were enhanced by a 20% increase in average commodity
prices on a natural gas equivalent basis. The drilling and workover success
increased our average daily production from 72.9 Mmcfe to 90.2 Mmcfe. Oil and
natural gas production volume totaled 8,302 Mmcfe for the third quarter of 2003,
compared to 6,705 Mmcfe for the comparable period of 2002. On a sequential
quarter basis, oil and natural gas daily production increased from 65.4 Mmcfe to
90.2 Mmcfe. Current production is ranging between 90 Mmcfe and 95 Mmcfe per day
and does not include the most recently announced Biloxi Marshlands No. 18-1
well, which tested at a daily production rate of approximately 16.5 Mmcfe/d and
is expected to be on production by or immediately after November 15, 2003.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended September 30, 2003
and 2002:
THREE MONTHS ENDED
SEPTEMBER 30,
-------------------- INCREASE
2003 2002 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 338 525 (36%)
Natural gas (MMcf) 6,275 3,556 76%
Mmcfe 8,302 6,705 24%
Average Sales Prices:
Oil (per Bbl) $ 24.46 $ 27.10 (10%)
Natural gas (per Mcf) $ 4.92 $ 3.44 43%
Mmcfe $ 4.71 $ 3.94 20%
Operating Revenues (000's):
Oil $ 8,268 $14,229 (42%)
Natural gas 30,861 12,216 153%
Total Operating Revenues $39,129 $26,445 48%
OPERATING EXPENSES. Oil and natural gas operating expenses were reduced by 20%
from $0.41 per Mcfe to $0.33 per Mcfe for the quarter ended September 30, 2003,
compared to the corresponding quarter of 2002. For the three months ended
September 30, 2003, and 2003, oil and gas operating expenses were relatively
unchanged. Oil and gas operating expenses reflect savings realized on sold
properties combined with other cost savings, offset by additional operating
expenses associated with the Biloxi Marshlands project area.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $0.5
million or 33% to $2.0 million for the third quarter of 2003, compared to $1.5
million during the same period in 2002. 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, an increase from $0.122 per Mcf
effective in July 2003. The Company's increase was primarily due to the increase
in natural gas production and the increase in the natural gas tax rate,
partially offset by the decrease
17
in oil prices and oil production. On an equivalent unit of production basis,
severance and ad valorem taxes increased to $0.24 per Mcfe from $0.23 per Mcfe
for the comparable three-month period.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $3.2
million or 17% during the third quarter of 2003 to $22.5 million, from $19.3
million for the same period of 2002. This was primarily the result of the 24%
increase in production volumes in 2003 over 2002 levels, partially offset by a
decrease in the depletion rate as compared to the 2002 period. On a unit basis,
depletion and depreciation expense decreased by $0.16 per Mcfe, to $2.71 per
Mcfe for the three months ended September 30, 2003, compared to $2.87 per Mcfe
for the same period in 2002.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expenses
decreased on an Mcfe unit basis by 19% from $0.43 per Mcfe for the three months
ended September 30, 2002, to $0.35 per Mcfe for the three months ended September
30, 2003, due primarily to the previously discussed production additions.
General and administrative expense remained flat at $2.9 million for the three
month periods ended September 30, 2003, and 2002, respectively.
As previously announced, during the first quarter of 2003, the Company initiated
reductions in staff to reflect its change in exploration strategy to lower-risk,
higher-probability projects, maintaining its focus in its niche region of south
Louisiana. Although the full impact of these reductions has not been fully
recognized because severance packages continue through this and future quarters,
we anticipate that these changes will result in future savings in costs without
sacrificing the Company's exploration efforts or opportunities.
IMPAIRMENT OF LONG-LIVED ASSETS. In 2002, a write-down in oil and natural gas
proved undeveloped reserves resulted in the Company recognizing a non-cash
impairment of $69.1 million of its oil and natural gas properties under the full
cost method of accounting.
INTEREST EXPENSE. Interest expense decreased $2.1 million or 43%, to $2.8
million for the third quarter of 2003 in comparison to the third quarter of
2002. The decrease is primarily a result of reduction in long-term debt by $41.7
million, or 20% year over year, for the period ending September 30, 2003, and a
decrease in interest rate from the prior year rate. Subsequent to September 30,
2003, the Company has made additional repayments on the outstanding borrowings
totaling $8.0 million.
CREDIT FACILITY RETIREMENT COSTS. During August 2002, the Company replaced its
Chase Manhattan Bank Credit Facility with a new three-year $175 million
underwritten senior secured credit agreement with Societe Generale and Fortis
Capital Corporation. Deferred debt costs associated with the prior credit
facility of $1.2 million were written off in September 2002.
18
NINE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 2002
OPERATING REVENUES. Oil and natural gas revenues during the nine months ended
September 30, 2003, increased $15.0 million as compared to revenues during the
nine months ended September 30, 2002, due to average sales prices increasing
38%, partially offset by a decrease in production volumes of 14%, both on a
natural gas equivalent basis. The production decrease is primarily a result of
the Avoca 47-1 and Thibodaux No. 1 wells being out of production during a
portion of the 2003 period and of natural production declines, partially offset
by four new wells from the Biloxi Marshlands project area brought on during
2003, the full impact of which will not be fully realized until mid-fourth
quarter 2003. Current production is ranging between 90 Mmcfe and 95 Mmcfe per
day and does not include the most recently announced Biloxi Marshlands No. 18-1
well, which tested at a daily production rate of approximately 16.5 Mmcfe/d and
is expected to be on production by or immediately after November 15, 2003.
The following table summarizes production volumes, average sales prices and
gross revenues for the nine months ended September 30, 2003 and 2002.
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------- INCREASE
2003 2002 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 1,082 1,789 (40%)
Natural gas (MMcf) 13,407 12,456 8%
Mmcfe 19,899 23,189 (14%)
Average Sales Prices:
Oil (Bbl) $ 24.95 $ 24.06 4%
Natural gas (Mcf) $ 5.28 $ 3.18 66%
Mmcfe $ 4.91 $ 3.57 38%
Gross Revenues (000's):
Oil $26,995 $43,051 (37%)
Natural gas 70,724 39,664 78%
Total $97,719 $82,715 18%
OPERATING EXPENSES. Oil and natural gas operating expenses decreased $0.8
million or 9% to $8.0 million for the nine months ended September 30, 2003,
compared to $8.8 million for the nine months ended September 30, 2002. Lease
operating expenses reflect savings realized on sold properties combined with
other cost savings offset by additional operating expenses associated with the
Biloxi Marshlands project area. On a unit basis, lease operating expenses
increased by $0.02 per Mcfe to $0.40 Mcfe for the nine months ended September
30, 2003, compared to $0.38 per Mcfe for the same period of 2003. This increase
was primarily related to lower production rates during the first nine months of
2003.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $1.2
million or 19% to $5.4 million for the nine months ended September 30, 2003,
compared to $6.6 million for the nine months ended September 30, 2002. This
decrease is largely attributable to the decrease in oil revenues from the same
period in 2002 and a decrease in the average tax rate for natural gas, partially
offset by the increase in natural gas production. Meridian's production is
primarily from southern Louisiana, and, therefore, is subject to a current tax
rate of 12.5% of gross oil revenues and $0.171 per Mcf for natural gas
(effective July 2003). The tax rate for natural gas for the first half of 2002
was $0.199 per Mcf, as compared to $0.122 per Mcf for the first half of 2003. 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 nine-month period.
19
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $6.1
million or 13% to $52.3 million during the first nine months of 2003 from $46.2
million for the same period last year. This increase was primarily a result of
an increased depletion rate from 2002 levels, partially offset by the 14%
decrease in production on an Mcfe basis from the comparable period in 2002. On a
unit basis, depletion and depreciation expenses increased to $2.63 per Mcfe for
the nine months ended September 30, 2003, compared to $1.99 per Mcfe for the
same period of 2002.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense decreased
$0.4 million or 5% to $8.7 million for the first nine months of 2003, compared
to $9.1 million during the first nine months of 2002. This reduction is
primarily due to a reduction in professional and technical services during 2003
compared to 2002 levels. On an equivalent unit of production basis, general and
administrative expenses increased to $0.44 per Mcfe, from $0.39 per Mcfe for the
comparable nine-month period due to the decrease in production during the first
three quarters of 2003.
As previously announced, during the first quarter of 2003 the Company initiated
reductions in staff to reflect its change in exploration strategy to lower-risk,
higher-probability projects, maintaining its focus in its niche region of south
Louisiana and southeast Texas. Although the full impact of these reductions has
not been fully recognized due to the severance packages included, it is
anticipated that these changes will result in future savings in costs without
sacrificing the Company's exploration efforts or opportunities.
IMPAIRMENT OF LONG-LIVED ASSETS. In 2002, a write-down in oil and natural gas
proved undeveloped reserves resulted in the Company recognizing a non-cash
impairment of $69.1 million of its oil and natural properties under the full
cost method of accounting.
INTEREST EXPENSE. Interest expense decreased $3.8 million or 30% to $8.7 million
during the first nine months of 2003 compared to $12.5 million during the
comparable period of 2002. The decrease is primarily a result of reduction in
long-term debt by $41.7 million, or 20% year over year, for the period ending
September 30, 2003, and a decrease in interest rate from the prior year rate.
Subsequent to September 30, 2003, the Company has made additional repayments on
the outstanding borrowings totaling $8.0 million.
CREDIT FACILITY RETIREMENT COSTS. During August 2002, the Company replaced its
Chase Manhattan Bank Credit Facility with a new three-year $175 million
underwritten senior secured credit agreement with Societe Generale and Fortis
Capital Corporation. Deferred debt costs associated with the prior credit
facility of $1.2 million were written off in September 2002.
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 $0.4 million to earnings as accretion expense during the nine
months ended September 30, 2003. 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
20
WORKING CAPITAL. During the third quarter of 2003, Meridian's capital
expenditures were internally financed with cash from operations. As of September
30, 2003, the Company had a cash balance of $17.6 million and a working capital
deficit of $3.4 million. This deficit was made up primarily of $5.0 million of
current maturities of long-term debt, and a $6.0 million net current liability
associated with price risk management activities. Since December 31, 2002, the
Company has increased its working capital by approximately $43.8 million.
Management's strategy is to grow the Company prudently, taking advantage of the
strong asset base built over the years to add reserves through the drill bit
while maintaining a disciplined approach to costs. Where appropriate, the
Company will allocate excess cash above capital expenditures to reduce leverage.
CASH FLOWS. Net cash provided by operating activities was $65.1 million for the
nine months ended September 30, 2003, as compared to $20.7 million for the same
period in 2002. The increase of $44.4 million was primarily due to the change in
operating assets and liabilities of $24.3 million, coupled with a $14.9 million
increase in natural gas revenues in the first nine months of 2003, as compared
to the first nine months of 2002. The decrease in current liabilities was the
primary reason for the $24.3 million net change in operating assets and
liabilities. Current liabilities decreased as a result of paying down these
liabilities with some of the proceeds from the preferred stock offering made in
2002.
Net cash used in investing activities was $52.9 million during the nine months
ended September 30, 2003, versus $55.2 million in the first nine months of 2002.
The decrease in 2003 was primarily due to a property sale during the nine months
ended September 30, 2003, as compared to the nine months ended September 30,
2002.
Cash flows used in financing activities during the first nine months of 2003
were $1.9 million, compared to cash provided by financing activities of $34.4
million during the first nine months of 2002.
The net increase of $10.3 million in cash and cash equivalents was primarily
associated with the increase in cash flows provided by operating activities in
the first nine months of 2003, as compared to the first nine months of 2002,
which enabled the Company to fund its capital projects primarily with cash flows
from operations without using debt financing.
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 $138.5 million and is scheduled to be redetermined and be effective on
January 31, 2004. Credit Facility payments of $26.7 million have been made
during the first nine months of 2003, bringing the outstanding balance to $138.3
million as of September 30, 2003. In October 2003, the Company made $8.0 million
in debt repayments and anticipates that it will continue to make 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 beginning with
those as of and for the year ended December 31, 2002. The Company has received
from the senior lenders a waiver of the covenant that would have triggered an
event of default as a result of the independent auditors' report which contained
a "going concern" modification for our 2002 consolidated financial statements.
21
Under the Credit Agreement, the Company may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate 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 a federal funds-based rate plus 1/2 of 1% 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. 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 4.5%
through December 31, 2002, 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.
A note payment of $5 million is due on April 30, 2004, with the remaining $5
million payable on December 31, 2004. Note payments totaling $8.75 million have
been paid in 2003, bringing the outstanding balance to $10.0 million as of
September 30, 2003. The Company is in compliance with the terms of this
agreement.
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
$55.6 million. Although the Company plans to commence additional drilling during
the remainder of 2003, such operations will depend primarily on permitting and
the availability of suitable drilling rigs. Meridian recently completed the
final field work on its 187-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.
Based on internal projections, using its internal risked analysis of production
based on an expected capital expenditures program for 2004 of $60-65 million,
the Company believes that it can further improve its balance sheet while, at the
same time, continuing its scheduled capital expenditure program, drilling ten to
fifteen low-risk wells and acquiring additional 3-D seismic data over its Biloxi
Marshlands project and other exploration areas targeted for exploration growth.
22
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. Under the
terms of the Credit Agreement, dividend payments required during 2003 on the
preferred stock have been paid-in-kind through our issuance of additional
preferred stock.
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.
23
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.
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 beginning April 30, 2003. 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 but largely dependent solely on the
discretion of its lenders.
24
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 $148.3 million remains borrowed under the Credit Facility
and the Subordinated Credit Agreement, we estimate our annual interest expense
will change by $1.483 million for each 100 basis point change in the applicable
interest rates utilized. 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 and our current stock price as it relates
to the conversion price of $5.00 per share of our Common Stock.
HEDGING CONTRACTS
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.
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.
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 our hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our 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 SFAS 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.
25
The estimated September 30, 2003, fair value of the Company's oil and natural
gas swaps is an unrealized loss of $8.6 million ($5.6 million net of tax)
recognized in other comprehensive income. Based upon September 30, 2003, oil and
natural gas commodity prices, approximately $6.0 million of the loss deferred in
other comprehensive income is expected to lower gross revenues over the next
twelve months when the revenues are generated. The swap agreements expire at
various dates through July 31, 2005.
Payments under these swap agreements reduced oil and natural gas revenues by
$2,608,000 for the three months and $12,739,000 for the nine months ended
September 30, 2003, as a result of hedging transactions.
The notional amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 11% of our proved developed natural gas production and 77% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at September 30, 2003
Amount ($ per unit) (in thousands)
--------- ---------------- ----------------------
Natural Gas (mmbtu)
October 2003 - June 2005 4,630,000 $ 3.75 $(4,952)
Oil (bbls)
October 2003 - July 2005 1,204,000 $23.81 $(3,601)
-------
$(8,553)
-------
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-14(c) under the
Securities Exchange Act of 1934) as of the end of the third quarter of 2003.
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 third quarter of 2003 that could
significantly affect these controls.
[See revised Item 307 of Reg. 5-K}
26
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
VERITAS LAWSUIT. On October 29, 2002, Veritas DGC Land Inc. ("Veritas Land")
filed a complaint against Meridian. The dispute concerns a contract for seismic
services for Meridian's Biloxi Marshlands project in St. Bernard Parish,
Louisiana. Meridian asserted a counterclaim. Purporting to invoke force majeure,
Veritas Land, together with Veritas DGC Inc. (collectively, "Veritas"),
unilaterally terminated the parties' contract. The main dispute is whether
Veritas had breached the parties' contract before the alleged force majeure
events and/or when it terminated the contract; Meridian has not made any
payments to Veritas under the parties' contract. Veritas' complaint seeks
breach-of-contract damages of approximately $6.8 million together with interest,
costs and attorneys' fees.
A settlement was reached October 31, 2003, calling for Meridian to pay $3.5
million to Veritas over six months, and requiring Veritas to pay its contractors
and release various liens associated with 3-D seismic data for 43 square miles,
which was delivered to us. This settlement has been fully reflected in the
Company's third quarter financial statements.
PETROQUEST LAWSUIT. On December 23, 1999, PetroQuest Energy, Inc. (formerly
known as Optima Energy (U.S.) Corporation) ("PetroQuest") filed a complaint
against Meridian seeking damages "estimat[ed] to exceed several million dollars"
for the Company's alleged gross negligence and willful misconduct under a letter
agreement dated October 6, 1993, between Meridian and PetroQuest and a master
participation agreement and joint operating agreement thereunder with respect to
certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in
Calcasieu Parish and certain agreements between Meridian and Amoco Production
Company ("Amoco"), and for alleged wrongful withholding of funds totaling
$886,153.31, as a result of Meridian's satisfying a prior adverse judgment in
favor of Amoco.
On April 4, 2002, Meridian filed an answer denying PetroQuest's claims and
asserted a counterclaim for declaratory relief that the Company is entitled to
retain the amounts (with all interest thereon) that it has suspended from
disbursement to PetroQuest and for attorneys' fees, courts costs and other
expenses incurred in this lawsuit or in connection with PetroQuest's failure to
timely pay the two invoices from Meridian. On or about April 22, 2002,
PetroQuest filed a "Reply and Defenses to Counterclaim," generally denying that
Meridian is entitled to the relief sought in its counterclaim. A trial date is
set for December 15, 2003.
There are no other material legal proceedings to which Meridian or any of its
subsidiaries or partnerships 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the annual meeting of shareholders held on July 15, 2003, the Company's
shareholders elected Class I Directors. The following summarizes the number of
votes for and against each nominee.
Broker
Nominee For Against Abstain Non-Vote
------- ---------- --------- ------- --------
James T. Bond 46,723,282 1,691,591 --- ---
Jack A. Prizzi 47,505,320 909,553 --- ---
27
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits
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.
The Company filed a Current Report on Form 8-K, dated July 29, 2003,
under Item 5, Other Events and Required FD Disclosure, regarding an
extension of item for compliance with certain provisions of the Credit
Facility.
The Company filed a Current Report on Form 8-K, dated August 21, 2003,
under Item 5, Other Events and Required FD Disclosure, providing
updated Risk Factors for investments in the Company's securities.
The Company filed a Current Report on Form 8-K, dated August 27, 2003,
under Item 5, Other Events and Required FD Disclosure, regarding the
offer and sale of 8,703,537 shares of the Company's common stock at a
purchase price of $3.87 per share.
The Company filed a Current Report on Form 8-K, dated September 30,
2003, under Item 4, Changes in Registrant's Certifying Accountants,
regarding the Company's retention of BDO Seidman LLP as the Company's
independent accountant.
28
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: November 13, 2003 By: /s/ LLOYD V. DELANO
--------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
29
INDEX TO EXHIBITS
Exhibit
No. Description
- ------- -----------
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.