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, 2005
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 1, 2005: 86,661,864
1
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, 2005 and 2004 3
Consolidated Balance Sheets as of June 30, 2005 (unaudited)
and December 31, 2004 4
Consolidated Statements of Cash Flows (unaudited) for the
Six Months Ended June 30, 2005 and 2004 6
Consolidated Statements of Stockholders' Equity (unaudited) for the
Six Months Ended June 30, 2005 and 2004 7
Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the
Three Months and Six Months Ended June 30, 2005 and 2004 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 4. Submission of Matters to a Vote of Security Holders 30
Item 6. Exhibits 31
SIGNATURES 32
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------ ------------------------------
2005 2004 2005 2004
------------ ------------ ------------ ------------
REVENUES:
Oil and natural gas $ 44,086 $ 50,065 $ 94,218 $ 96,205
Price risk management activities (168) ----- (460) -----
Interest and other 185 38 389 90
------------ ------------ ------------ ------------
44,103 50,103 94,147 96,295
------------ ------------ ------------ ------------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 4,109 2,746 8,792 5,754
Severance and ad valorem taxes 1,866 2,512 4,498 4,829
Depletion and depreciation 25,405 25,352 50,727 49,053
General and administrative 4,371 3,491 9,384 6,695
Accretion expense 275 148 526 267
------------ ------------ ------------ ------------
36,026 34,249 73,927 66,598
------------ ------------ ------------ ------------
EARNINGS BEFORE INTEREST AND INCOME TAXES 8,077 15,854 20,220 29,697
------------ ------------ ------------ ------------
OTHER EXPENSES:
Interest expense 1,097 1,801 2,082 3,970
Debt conversion expense ----- ----- ----- 1,188
------------ ------------ ------------ ------------
1,097 1,801 2,082 5,158
------------ ------------ ------------ ------------
EARNINGS BEFORE INCOME TAXES 6,980 14,053 18,138 24,539
------------ ------------ ------------ ------------
INCOME TAXES:
Current (333) 1,100 257 2,100
Deferred 3,016 4,100 6,726 7,000
------------ ------------ ------------ ------------
2,683 5,200 6,983 9,100
------------ ------------ ------------ ------------
NET EARNINGS: 4,297 8,853 11,155 15,439
Dividends on preferred stock 171 1,108 902 2,407
------------ ------------ ------------ ------------
NET EARNINGS APPLICABLE
TO COMMON STOCKHOLDERS $ 4,126 $ 7,745 $ 10,253 $ 13,032
============ ============ ============ ============
NET EARNINGS PER SHARE:
Basic $ 0.05 $ 0.11 $ 0.12 $ 0.20
Diluted $ 0.05 $ 0.10 $ 0.12 $ 0.18
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 85,277 69,304 82,291 66,157
Diluted 90,770 75,363 87,914 73,566
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
JUNE 30, DECEMBER 31,
2005 2004
------------ ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 13,638 $ 24,297
Restricted cash 2,893 891
Accounts receivable, less allowance for doubtful accounts of
$242 [2005 and 2004] 21,246 27,763
Prepaid expenses and other 3,864 2,263
Assets from price risk management activities 264 5,705
------------ ------------
Total current assets 41,905 60,919
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $40,693 [2005] and $34,731 [2004]
not subject to depletion) 1,454,163 1,377,649
Land 479 478
Equipment and other 10,168 10,039
------------ ------------
1,464,810 1,388,166
Less accumulated depletion and depreciation 989,690 938,965
------------ ------------
Total property and equipment, net 475,120 449,201
------------ ------------
OTHER ASSETS 1,114 2,272
------------ ------------
TOTAL ASSETS $ 518,139 $ 512,392
============ ============
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
JUNE 30, DECEMBER 31,
2005 2004
------------ ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 14,761 $ 14,983
Revenues and royalties payable 6,815 8,117
Due to affiliates 3,463 3,866
Notes payable 2,008 870
Accrued liabilities 13,738 21,406
Liabilities from price risk management activities 5,827 8,003
Asset retirement obligations 2,243 1,331
Current income taxes payable ----- 105
------------ ------------
Total current liabilities 48,855 58,681
------------ ------------
LONG-TERM DEBT 75,129 75,129
------------ ------------
OTHER:
Deferred income taxes 28,307 22,639
Liabilities from price risk management activities 234 -----
Asset retirement obligations 8,220 8,293
Other 9 20
------------ ------------
36,770 30,952
COMMITMENTS AND CONTINGENCIES (NOTE 5)
REDEEMABLE CONVERTIBLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
None [2005] and 315,886 [2004] shares of Series C
Redeemable Convertible Preferred Stock issued at stated value) ----- 31,589
------------ ------------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
86,661,864 [2005] and 79,215,394 [2004] outstanding) 897 821
Additional paid-in capital 523,394 490,351
Accumulated deficit (162,991) (173,244)
Accumulated other comprehensive loss (3,544) (1,574)
Unamortized deferred compensation (371) (313)
------------ ------------
Total stockholders' equity 357,385 316,041
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 518,139 $ 512,392
============ ============
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,
------------------------------
2005 2004
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 11,155 $ 15,439
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depletion and depreciation 50,727 49,053
Amortization of other assets 216 971
Non-cash compensation 939 1,020
Non-cash price risk management activities 460 -----
Debt conversion expense ----- 1,188
Accretion expense 526 267
Deferred income taxes 6,726 7,000
Changes in assets and liabilities:
Restricted cash (2,002) -----
Accounts receivable 6,517 958
Prepaid expenses and other (1,601) (1,361)
Due to affiliates (403) 125
Accounts payable (222) 1,060
Revenues and royalties payable (1,302) (4,716)
Accrued liabilities and other (4,973) 3,303
------------ ------------
Net cash provided by operating activities 66,763 74,307
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (76,259) (59,620)
Proceeds from (settlements on) sale of property (55) (125)
------------ ------------
Net cash used in investing activities (76,314) (59,745)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt ----- (13,320)
Increase in notes payable, net 1,138 1,403
Issuance of stock/exercise of options, net 13 222
Preferred dividends (2,166) (3,872)
Additions to deferred loan costs (93) (13)
------------ ------------
Net cash used in financing activities (1,108) (15,580)
------------ ------------
NET DECREASE IN CASH AND CASH EQUIVALENTS (10,659) (1,018)
Cash and cash equivalents at beginning of period 24,297 12,821
------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 13,638 $ 11,803
============ ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ (30,625) $ (28,075)
Issuance of shares for settlement of accrued liabilities (1,484) -----
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, 2005 AND 2004
(in thousands)
(unaudited)
Accumulated
Common Stock Additional Other Unamortized
------------------ Paid-In Accumulated Comprehensive Deferred
Shares Par Value Capital (Deficit) Loss Compensation Total
------ --------- ---------- ----------- ------------- ------------ ----------
Balance, December 31, 2003 61,725 $ 644 $ 394,177 $ (202,492) $ (7,704) $ (290) $ 184,335
Issuance of rights to common stock ----- 2 923 ----- ----- (925) -----
Company's 401(K) plan contribution 31 ----- 185 ----- ----- ----- 185
Exercise of stock options 8 ----- 37 ----- ----- ----- 37
Compensation expense ----- ----- ----- ----- ----- 835 835
Accum. other comprehensive income ----- ----- ----- ----- (970) ----- (970)
Issuance for conversion of pref stock 6,308 63 26,920 ----- ----- ----- 26,983
Issuance for conversion of sub debt 4,209 42 21,146 ----- ----- ----- 21,188
Preferred dividends ----- ----- ----- (2,407) ----- ----- (2,407)
Net earnings ----- ----- ----- 15,439 ----- ----- 15,439
------ --------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 2004 72,281 $ 751 $ 443,388 $ (189,460) $ (8,674) $ (380) $ 245,625
====== ========= ========== ========== ========== ========== ==========
Balance, December 31, 2004 79,215 $ 821 $ 490,351 $ (173,244) $ (1,574) $ (313) $ 316,041
Issuance of rights to common stock ----- 2 910 ----- ----- (912) -----
Exercise of stock options 49 ----- 163 ----- ----- ----- 163
Company's 401(K) plan contribution 16 ----- 85 ----- ----- ----- 85
Compensation expense ----- ----- ----- ----- ----- 854 854
Accum. other comprehensive income ----- ----- ----- ----- (1,970) ----- (1,970)
Issuance for conversion of pref stock 7,099 71 30,554 ----- ----- ----- 30,625
Expenditures assoc. w/stock offering ----- ----- (150) ----- ----- ----- (150)
Issuance to settle accrued liabilities 283 3 1,481 ----- ----- ----- 1,484
Preferred dividends ----- ----- ----- (902) ----- ----- (902)
Net earnings ----- ----- ----- 11,155 ----- ----- 11,155
------ --------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 2005 86,662 $ 897 $ 523,394 $ (162,991) $ (3,544) $ (371) $ 357,385
====== ========= ========== ========== ========== ========== ==========
See notes to consolidated financial statements.
7
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2005 2004 2005 2004
---------- ---------- ---------- ----------
Net earnings applicable to common stockholders $ 4,126 $ 7,745 $ 10,253 $ 13,032
Other comprehensive income (loss), net of tax, for unrealized
losses from hedging activities:
Unrealized holding gains (losses) arising during period (1) 2,280 (2,445) (6,405) (6,080)
Reclassification adjustments on settlement of contracts (2) 3,223 2,760 4,435 5,110
---------- ---------- ---------- ----------
$ 5,503 315 (1,970) (970)
---------- ---------- ---------- ----------
Total comprehensive income $ 9,629 $ 8,060 $ 8,283 $ 12,062
========== ========== ========== ==========
(1) net of income tax (expense) benefit $ (1,227) $ 1,316 $ 3,449 $ 3,274
(2) net of income tax expense $ (1,736) $ (1,486) $ (2,388) $ (2,751)
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, 2004, as filed with the Securities and Exchange Commission.
The financial statements included herein as of June 30, 2005, and for the three
month and six month periods ended June 30, 2005 and 2004, 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. ACCRUED LIABILITIES
Below is the detail of our accrued liabilities on our balance sheets as of June
30, 2005 and December 31, 2004 (thousands of dollars):
JUNE 30, DECEMBER 31,
2005 2004
------------ ------------
Capital Expenditures $ 8,841 $ 12,662
Bonuses 941 3,355
Dividends ----- 1,346
Other 3,956 4,043
------------ ------------
TOTAL $ 13,738 $ 21,406
============ ============
3. DEBT
CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit
facility to provide for a four-year $200 million senior secured credit facility
(the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole
lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank
of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
p.l.c., RZB Finance LLC and Standard Bank PLC completed the syndication group.
The initial borrowing base under the Credit Facility is $130 million and it has
been reaffirmed by the syndication group effective April 30, 2005. As of June
30, 2005, outstanding borrowings under the Credit Facility totaled $75.1
million.
9
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and gas properties. In addition, the Company is required to deliver
to the lenders and maintain satisfactory title opinions covering not less than
70% of the present value of proved oil and gas properties. The Credit Facility
also contains other restrictive covenants, including, among other items,
maintenance of certain financial ratios, restrictions on cash dividends on
Common Stock and under certain circumstances Preferred Stock, limitations on the
redemption of Preferred Stock and an unqualified audit report on the Company's
consolidated financial statements, with which the Company is in compliance.
Under the Credit Facility, 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 1.25% 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 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At June 30, 2005, the three-month LIBOR interest rate was
3.52%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
4. 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 was convertible into
shares of the Company's Common Stock at a conversion price of $4.45 per share.
Dividends were payable semi-annually in cash or additional preferred stock. At
the option of the Company, one-third of the preferred shares could be forced to
convert to Common Stock if the closing price of the Company's Common Stock
exceeded 150% of the conversion price for 30 out of 40 consecutive trading days
on the New York Stock Exchange. The preferred stock was subject to redemption at
the option of the Company after March 2005, and mandatory redemption on March
31, 2009. During the first six months of 2005, the Company completed the
conversion of all of the remaining outstanding shares of preferred stock to
Common Stock, with $31.6 million of stated value being converted into
approximately 7.1 million shares of the Company's Common Stock.
5. COMMITMENTS AND CONTINGENCIES
LITIGATION.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence and willful misconduct under certain
agreements concerning certain wells and property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish of Louisiana, as a result of
Meridian's satisfying a prior adverse judgment in favor of Amoco Production
Company. Meridian has filed an answer denying Hawkins' claims and asserted a
counterclaim for attorney's fees, court costs and other expenses, and for
declaratory relief that Meridian is entitled to retain the amounts that it had
been paid by Hawkins. The Company has not provided any amount for this matter in
its financial statements at June 30, 2005.
10
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning several
fields in which the Company has had operations. 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. The Company has not provided any amount for
these matters in the financial statements at June 30, 2005.
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed 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.
6. STOCKHOLDERS' EQUITY
COMMON STOCK. 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 $94.6 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 that equity offering was used
to repay borrowings under the Company's senior secured credit agreement, which
resulted in an increase in funds available to the Company to accelerate planned
capital expenditures for drilling activities and related pipeline construction.
The repurchased 7,082,030 shares of Common Stock that were held in Treasury
Stock were retired as of September 30, 2004. As previously noted, during the six
months ended June 30, 2004, 6.3 million shares of Common Stock were issued for
the conversion of the 8.5% Redeemable Convertible Preferred Stock and 4.2
million shares of Common Stock was issued for the early retirement of the 9
-1/2% Convertible Subordinated Notes. During the the first six months of 2005,
the Company completed the conversion of all of the remaining outstanding shares
of the 8.5% Redeemable Convertible Preferred Stock with the issuance of
approximately 7.1 million shares of the Company's Common Stock.
11
7. 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,
-------------------------------
2005 2004
------------ ------------
Numerator:
Net earnings applicable to common stockholders $ 4,126 $ 7,745
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes ----- -----
------------ ------------
Net earnings applicable to common stockholders
plus assumed conversions $ 4,126 $ 7,745
------------ ------------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 85,277 69,304
Effect of potentially dilutive common shares:
Warrants 4,746 4,443
Employee and director stock options 747 1,616
Convertible subordinated notes ----- -----
Redeemable preferred stock N/A N/A
------------ ------------
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions 90,770 75,363
============ ============
Basic earnings per share $ 0.05 $ 0.11
============ ============
Diluted earnings per share $ 0.05 $ 0.10
============ ============
SIX MONTHS ENDED JUNE 30,
-------------------------------
2005 2004
------------ ------------
Numerator:
Net earnings applicable to common stockholders $ 10,253 $ 13,032
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes ----- 270
------------ ------------
Net earnings applicable to common stockholders
plus assumed conversions $ 10,253 $ 13,302
------------ ------------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 82,291 66,157
Effect of potentially dilutive common shares:
Warrants 4,641 4,240
Employee and director stock options 982 1,455
Convertible subordinated notes ----- 1,714
Redeemable preferred stock N/A N/A
------------ ------------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 87,914 73,566
============ ============
Basic earnings per share $ 0.12 $ 0.20
============ ============
Diluted earnings per share $ 0.12 $ 0.18
============ ============
12
8. 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. 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 by the
counter-party, 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 Company recognized a loss related to hedge ineffectiveness of approximately
$0.2 million during the three months and approximately $0.5 million during the
six months ended June 30, 2005, and none during the three and six months ended
June 30, 2004.
The estimated June 30, 2005 fair value of the Company's oil and natural gas
derivatives was a net unrealized loss of $5.5 million ($3.5 million net of tax)
which is recorded in Accumulated Other Comprehensive Loss on the Company's
consolidated balance sheet. Based upon June 30, 2005 oil and natural gas
commodity prices, approximately $5.6 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, 2006.
Net settlements under these swap agreements reduced oil and natural gas revenues
by $4,959,000 and $4,247,000 for the three months ended June 30, 2005 and 2004,
respectively, and by $6,823,000 and $7,861,000 for the six months ended June 30,
2005 and 2004, 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 42% of the proved developed natural gas production and 34% of the
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 fair value of the hedging agreements is recorded on our consolidated balance
sheet as separately identified assets or liabilities, except for $11 thousand
included in Other Assets. The estimated fair value of our hedging agreements as
of June 30, 2005, is provided below:
13
Swap / Floor Ceiling Fair Value
Notional Price Price June 30, 2005
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ -------------- --------------
NATURAL GAS (MMBTU)
Jul 2005 Swap 130,000 $ 3.74 N/A $ (420)
Jul 2005 - Oct 2005 Swap 1,450,000 $ 6.34 N/A (1,061)
Jul 2005 - Oct 2005 Collar 1,450,000 $ 6.50 $ 7.90 35
--------------
Total Natural Gas (1,446)
--------------
CRUDE OIL (BBLS)
Jul 2005 Swap 38,000 $ 23.00 N/A (1,253)
Aug 2005 - Jul 2006 Collar 209,000 $ 37.50 $ 47.50 (2,597)
Aug 2005 - Jul 2006 Collar 48,000 $ 40.00 $ 50.00 (490)
--------------
Total Crude Oil (4,340)
--------------
$ (5,786)
==============
9. 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 or six month periods
ended June 30, 2005 and 2004.
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,
-------------------------------------
2005 2004
-------------- --------------
Net earnings applicable to common stockholders as reported $ 4,126 $ 7,745
Stock-based compensation (expense) benefit determined under
fair value method for all awards, net of tax (40) (4)
-------------- --------------
Net earnings applicable to common stockholders pro forma $ 4,086 $ 7,741
============== ==============
Basic earnings per share:
As reported $ 0.05 $ 0.11
Pro forma $ 0.05 $ 0.11
Diluted earnings per share:
As reported $ 0.05 $ 0.10
Pro forma $ 0.05 $ 0.10
14
(In thousands, except per share data)
Six Months Ended June 30,
-------------------------------------
2005 2004
-------------- --------------
Net earnings applicable to common stockholders as reported $ 10,253 $ 13,032
Stock-based compensation expense determined under
fair value method for all awards, net of tax (98) (8)
-------------- --------------
Net earnings applicable to common stockholders pro forma $ 10,155 $ 13,024
============== ==============
Basic earnings per share:
As reported $ 0.12 $ 0.20
Pro forma $ 0.12 $ 0.20
Diluted earnings per share:
As reported $ 0.12 $ 0.18
Pro forma $ 0.12 $ 0.18
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
Statement 95 "Statement of Cash Flows". This statement addresses the accounting
for share-based payment transactions in which an enterprise receives employee
services in exchange for (a) equity instruments of the enterprise or (b)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
The statement would eliminate the ability to account for share-based
compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued
to Employees," and generally would require instead that such transactions be
accounted for using a fair-value-based method. This statement will be effective
for the Company for interim periods beginning after December 15, 2005. The
impact on the results of operations would be similar to the pro forma
disclosures made above.
10. 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.
15
The following table describes the change in the Company's asset retirement
obligations for the six months ended June 30, 2005, and for the year ended
December 31, 2004 (thousands of dollars):
Asset retirement obligation at December 31, 2003 $ 4,102
Additional retirement obligations recorded in 2004 1,051
Settlements during 2004 (972)
Revisions to estimates during 2004 4,842
Accretion expense for 2004 601
---------
Asset retirement obligation at December 31, 2004 9,624
Additional retirement obligations recorded in 2005 495
Settlements during 2005 (182)
Accretion expense for 2005 526
---------
Asset retirement obligation at June 30, 2005 $ 10,463
=========
11. NEW ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
Statement 95, "Statement of Cash Flows." This statement addresses the accounting
for share-based payment transactions in which an enterprise receives employee
services in exchange for (a) equity instruments of the enterprise or (b)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
The statement would eliminate the ability to account for share-based
compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued
to Employees," and generally would require instead that such transactions be
accounted for using a fair-value-based method. This statement will be effective
for the Company for interim periods beginning after December 15, 2005. The
impact on the results of operations would be similar to the pro forma
disclosures presented in Note 9.
In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for
Conditional Asset Retirement Obligations." This interpretation clarifies the
definition and treatment of conditional asset retirement obligations as
discussed in FASB Statement No. 143, "Accounting for Asset Retirement
Obligations." A conditional asset retirement obligation is defined as an asset
retirement activity in which the timing and/or method of settlement are
dependent on future events that may be outside the control of the Company. FIN
47 states that a Company must record a liability when incurred for conditional
asset retirement obligations if the fair value of the obligation is reasonably
estimable. This interpretation is intended to provide more information about
long-lived assets, more information about future cash outflows for these
obligations and more consistent recognition of these liabilities. FIN 47 is
effective for fiscal years ending after December 15, 2005. The Company does not
believe that its financial position, results of operations or cash flows will be
impacted by this interpretation.
In May 2005, the FASB issued Statement of Financial Accounting Standards (SFAS)
No. 154, "Accounting Changes and Error Corrections -- a replacement of APB
Opinion No. 20 and FASB Statement No. 3." In order to enhance financial
reporting consistency between periods, SFAS 154 modifies the requirements for
the accounting and reporting of the direct effects of changes in accounting
principles. Under APB Opinion 20, the cumulative effect of voluntary changes in
accounting principle was recognized in Net Income in the period of the change.
Unlike the treatment previously prescribed by APB Opinion 20, retrospective
application is now required, unless it is not practical to determine the
specific effects in each period or the cumulative effect. If the period specific
effects cannot be determined, it is required that the new accounting principle
must be retrospectively applied in the earliest period possible to the balance
sheet accounts and a corresponding adjustment be made to the opening balance of
retained earnings or another equity account. If the cumulative effect cannot be
determined, it is necessary to apply the new accounting principles prospectively
at the earliest practical date. If it is not feasible to retrospectively apply
the change in principle, the reason that this is not possible and the method
used to report the change are required to be disclosed. The statement also
provides
16
that changes in accounting for depreciation, depletion or amortization should be
treated as changes in accounting estimate inseparable from a change in
accounting principle and that disclosure of the preferability of the change is
required. SFAS 154 is effective for accounting changes made in fiscal years
beginning after December 15, 2005.
12. SUBSEQUENT EVENT
During July 2005, the Company entered into a series of hedging contracts to
hedge a portion of its oil and natural gas production for 2005, 2006 and 2007.
The hedge contracts were completed in the form of costless collars. The costless
collars provide the Company with a lower floor price and an upper limit ceiling
price on the hedge volumes. The floor price represents the lowest price the
Company will receive for the hedge volumes, while the ceiling price represents
the highest price the Company will receive for the hedged volumes. The costless
collars will be settled monthly based on the daily settlement price of the NYMEX
futures contract of oil and natural gas during each respective month. The
following table summarizes the contracted volumes and price for the costless
collars.
Notional Floor Price Ceiling Price
Amount ($ per unit) ($ per unit)
--------- ------------ -------------
NATURAL GAS (MMBTU)
Nov 2005 - Mar 2006 2,980,000 $ 7.50 $ 11.25
CRUDE OIL (BBLS)
Aug 2006 - Jul 2007 168,000 $ 50.00 $ 76.00
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, 2005 and 2004. 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, 2004 (and the notes attached thereto),
should be read in conjunction with this discussion.
GENERAL.
EAST TEXAS JOINT VENTURE -- Meridian recently entered into a Joint Exploration
Agreement for the exploration and development of an extension play offsetting
the Double A field located in the east Texas region in Tyler and Polk counties.
The Double A field is primarily a Woodbine development that has produced over
390 Bcf and 17 million barrels of oil since its discovery during the 1980's.
Meridian is the operator and has obtained a rig for the drilling of the first
well in the project area, which subject to permitting, title and location
contingencies, is expected to begin during late third quarter. The Company and
its affiliates own a 50% working interest in the venture.
BILOXI MARSHLANDS PROJECT -- The Company recently completed drilling the Apache
La. Minerals No. 1 well on its Bayou Gentilly prospect to a total depth of
approximately 12,600 feet. The well was tested from the geo-pressured Cris "I"
sand interval at a gross daily flow rate as high as 5.9 million cubic feet of
gas ("Mmcf") and 654 barrels of condensate ("BC") on a 10/64th-inch choke at a
flowing tubing pressure of 6,018 psi and 8,200 psi shut-in tubing pressure. The
well was tested from 14 feet of perforations between 11,758 feet and 11,772
feet. Production from the well will require construction of a pipeline and
production facilities. The Company has set a goal of having the well completed
and producing during the fourth quarter of this year. The Company owns a 92%
working interest in this well.
The rig from the Bayou Gentilly well has been moved to the northeast quadrant of
the Biloxi Marshlands ("BML") play to drill its Menifee prospect. This prospect
will be a normal pressured test at approximately 9,000 feet. Following drilling
of the Menifee prospect, the Company plans to utilize this rig for the drilling
of several additional prospects in the northeast quadrant of the BML project
area, beginning with the Gato del Sol and Seabiscuit prospects.
During the second quarter, the Company completed its fourth and final phase of
new proprietary 3-D seismic acquisition covering approximately 140 square miles
gross (90 square miles net) primarily in the southwest quadrant of its 400,000
acre 3-D shoot. This data is currently in processing and, based on initial
interpretation, appears similar in quality and prospectivity to the Company's
400 square mile proprietary 3-D seismic data previously shot over this region.
The company expects to complete processing and interpretation of the data set
well in advance of its option date of December 15, 2005. To date, the Company
has expended approximately $179 million in the development of the BML project
which has returned over $172 million of its investment. Since inception of the
BML project, the Company has drilled 34 wells with 21 producers. During the
first half of 2005, the Company participated in four state lease sales and has
been successful in acquiring all targeted acreage. The Company believes that its
knowledge base and understanding of the region together with its large
proprietary 3-D seismic data provide it with a competitive advantage to continue
to acquire and develop this play as originally planned.
The String of Pearls SL 18315 No. 1 well has been placed on production effective
mid-July following the completion of a pipeline. The well is producing from the
Basal Deltaic sand section and is currently producing 4 Mmcf/d gross (2.7 Mmcf/d
net) of gas through a 17/64th-inch choke with a flowing tubing pressure measured
at 2,300 psi. The Company owns a 92% working interest in this well.
Operations to re-drill the Company's BML No. 1-2 well in St. Bernard Parish have
been temporarily halted following a drilling rig incident related to Hurricane
Dennis in early July. While the barge rig was being
18
relocated as part of its hurricane preparation efforts, the rig took on water,
tipping over onto its side in Bayou Grande about 1,200 feet from the well
location. All personnel were safely evacuated with no injuries. At the time of
the incident, the well was being re-drilled to the same productive interval in
which the well had been previously completed. The re-drill was about 2,000 feet
from its targeted depth before the incident. During the second quarter, the BML
No. 1-2 well was producing approximately 7.5 Mmcf/d gross (3.7 Mmcf/d net) when
it experienced down hole mechanical problems and ceased producing. Meridian
anticipates moving another rig onto the well and finishing the work as soon as
the barge rig is up righted and removed. The Company anticipates that the rig
will be removed within the next 30 to 45 days.
Other activity in the BML area during the second quarter included the drilling
of the SL 18157 No. 1 well located on the Pan Prospect area to a depth of
approximately 9,000 feet for a Cris "I" sand test. The well encountered 2 sands
indicating hydrocarbons, but not in sufficient quantities to justify completion
and construction of pipeline and production facilities. The well has
subsequently been abandoned. Additionally, the Company drilled the SL 18072 No.
1 well located in the East Stuards Bluff area to a depth of approximately 10,800
feet to test the Big Hum and Tex W sands that are producing in offset wells
drilled by Meridian in the immediate area. The well also encountered sands
indicating hydrocarbons, but not in sufficient quantities to justify completing
the well and was subsequently abandoned.
RAMOS COMPLEX AREA - The Company previously announced the initial production
test results of the Avoca 6-1 well in the Bayou Chene prospect area, and the
Avoca 5-2 well in the N.W. Bayou Chene prospect area of approximately 6.5 Mmcf/d
gross and 214 BC gross (5 Mmcfe/d net) and approximately 2.3 Mmcf/d gross (1.5
Mmcf/d net), respectively, with no accompanying water production. Production
from the wells required construction of a pipeline and production facilities.
The anticipated completion of this project is currently scheduled for late third
quarter versus the previously stated anticipated completion date of early third
quarter. The Company owns 92% working interest in the well.
The outside operated Shepard et al No. 1 well in the Black Bayou prospect area
was drilled to 3,000 feet and logged gas pay in a shallow Miocene sand section.
The well has recently been completed and tested by the operator on August 5,
2005. Production from the well will require construction of a pipeline and
production facilities, at which time the production rate will be reported. The
Company has set a goal of having the construction completed and the well
producing during the fourth quarter of 2005. The Company owns a 46% working
interest in the well.
The CL&F C-1 well in the Turtle Cove prospect area was drilled to a depth of
approximately 13,200 feet, logged gas pay in the Big Hum sand and was completed.
Soon after an initial test of 750 Mcf/d, flowing pressures from the well dropped
significantly. Further work on the well failed to stimulate additional
production. The Company is currently evaluating the well to determine its
economic viability. The drilling rig was next utilized to drill the CL&F D-1
well on the Turtle Bay prospect. The well was drilled to a depth of
approximately 12,000 feet to test a Big Hum amplitude anomaly. The sand was
encountered where expected, but appears to have been depleted and the well was
subsequently plugged and abandoned.
The rig is currently drilling the CL&F E-1 well on the Company's Turtle Shell
prospect. This well is currently drilling at approximately 12,000 feet, going to
a total depth of approximately 17,000 feet to test several potentially
productive objectives including the Rob L and multiple Cib Op sands. Upon
completion of the Turtle Shell well, the Company plans to utilize this rig for
the drilling of additional prospects in the Ramos Complex project area.
Additionally, in the Ramos Complex area, the SL 16049 well was shut-in at the
beginning of the second quarter due to scaling inside the production tubing. The
well was producing from the Operc 5 sand at a rate of 5.5 Mmcfe/d gross (2.8
Mmcfe/d net). Currently the well is being worked over and the Company
anticipates that this well will be returned to production at comparable levels.
19
MISCELLANEOUS OPERATIONS/PRODUCTION - Elsewhere during the second quarter, the
Company participated in a well in the Gibson Humphrey field. The outside
operated well was drilled to a depth of approximately 13,000 feet, was completed
and is producing at a rate of 1.9 Mmcf/d gross (500 Mcf/d net). The Company owns
a 29% working interest in the well. Additionally, the Company participated in
the drilling of the Evelyn Moulis No. 1 well on the North by Northwest prospect.
The well was drilled to a depth of approximately 7,000 feet and failed to
encounter hydrocarbons. It was subsequently plugged and abandoned.
Average daily production volumes for the second quarter of 2005 totaled 76.2
Mmcfe compared to 86.3 Mmcfe for the first quarter of 2005, representing a
decline of 10.1 Mmcfe. Approximately 6.5 Mmcfe/d of the 10.1 Mmcfe/d difference
is the result of mechanical issues on two wells (BML 1-2 and SL 16049) which are
currently being addressed as discussed above. The remainder is due to delays in
placing recent discoveries on line, and natural production declines.
Average daily production volumes for the first six months of 2005 totaled 81.2
Mmcfe compared to 96.7 Mmcfe for the corresponding period of 2004, representing
a decline of 15.5 Mmcfe. Approximately 12.5 Mmcfe of the 15.5 Mmcfe difference
is the result of mechanical issues on the Ramos - SL 16049 No. 1 well discussed
above, and the Ramos Thibodeaux No. 3 well. The Thibodeaux No. 3 well, which, as
reported in the Company's first quarter 2005 results, began making significant
amounts of water due to channeling from a lower zone during late 2004. The well
was subsequently shut-in and workover operations were performed to attempt to
minimize the water production. The well was returned to production during May
2005 at a rate of 3.5 Mmcfe/d (1.6 Mmcfe/d net).
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, 2005,
was $31.14 per barrel compared to $27.36 per barrel for the three months ended
June 30, 2004, and $33.99 per barrel for the three months ended March 31, 2005.
Our average natural gas price (after adjustments for hedging activities) for the
three months ended June 30, 2005, was $6.63 per Mcf compared to $5.86 per Mcf
for the three months ended June 30, 2004, and $6.66 per Mcf for the three months
ended March 31, 2005. 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, 2004, for further discussion.
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004
OPERATING REVENUES. Second quarter 2005 oil and natural gas revenues, which
include oil and natural gas hedging activities (see Note 8 of Notes to
Consolidated Financial Statements), decreased $6.0 million (12%) as compared to
second quarter 2004 revenues due to a 23% decrease in production volumes
primarily due to mechanical issues on two wells (SL 16049 #1 and Thibodeaux #3)
in the Ramos Complex area and natural production declines, partially offset by a
14% increase in average commodity prices on a natural gas equivalent basis. Our
average daily production decreased from 99 Mmcfe during the second quarter of
2004 to 76 Mmcfe for the second quarter of 2005. Oil and natural gas production
volume totaled 6,931 Mmcfe for the second
20
quarter of 2005, compared to 9,002 Mmcfe for the comparable period of 2004.
21
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended June 30, 2005 and
2004:
THREE MONTHS ENDED
JUNE 30, INCREASE
2005 2004 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 217 346 (37%)
Natural gas (MMcf) 5,630 6,927 (19%)
Mmcfe 6,931 9,002 (23%)
Average Sales Prices:
Oil (per Bbl) $ 31.14 $ 27.36 14%
Natural gas (per Mcf) $ 6.63 $ 5.86 13%
Mmcfe $ 6.36 $ 5.56 14%
Operating Revenues (000's):
Oil $ 6,757 $ 9,467 (29%)
Natural gas 37,329 40,598 (8%)
------- -------
Total Operating Revenues $44,086 $50,065 (12%)
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $1.4 million (50%) to $4.1 million during the second quarter of 2005,
compared to $2.7 million in 2004. On a unit basis, lease operating expenses
increased $0.28 per Mcfe to $0.59 per Mcfe for the second quarter of 2005 from
$0.31 per Mcfe for the second quarter of 2004. Oil and gas operating expenses
increased due to additional operating expenses associated with the increase in
wells and facilities in the Biloxi Marshlands project area, and to increased
workover related expenses of approximately $0.9 million, primarily at Weeks
Island.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.6
million (26%) to $1.9 million for the second quarter of 2005, compared to $2.5
million during the same period in 2004 primarily because of a decrease in oil
and natural gas production, partially offset by an increase in oil prices 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 were
$0.208 per Mcf for natural gas, an increase from $0.171 per Mcf for the first
half of 2004. On an equivalent unit of production basis, severance and ad
valorem taxes decreased to $0.27 per Mcfe from $0.28 per Mcfe for the comparable
three-month period. Beginning July 1, 2005, the revised severance tax rate for
natural gas production in Louisiana over the next twelve months will be $0.252
per Mcf. This will significantly increase the amount of severance taxes being
paid in future periods.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $0.1
million during the second quarter of 2005 to $25.4 million. This was primarily
the result of an increase in the depletion rate as compared to the 2004 period,
partially offset by the decrease in oil and natural gas production. During the
second quarter of 2005, the Company suspended operations to re-drill a well on
its North Turtle Bayou prospect after unsuccessful attempts to reestablish
production from the well. As a result, the Company revised its earlier reserve
estimates associated with the well resulting in a higher depletion and
depreciation rate coupled with the addition of costs related to unsuccessful
wells drilled during 2005. On a unit basis, depletion and depreciation expense
increased by $0.85 per Mcfe, to $3.67 per Mcfe for the three months ended June
30, 2005, compared to $2.82 per Mcfe for the same period in 2004.
22
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$0.9 million to $4.4 million compared to $3.5 million for 2004. The increase was
primarily the result of increased professional services, accounting fees and
increased operating activities. On an equivalent unit of production basis,
general and administrative expenses increased $0.24 per Mcfe to $0.63 per Mcfe
for the second quarter of 2005 compared to $0.39 per Mcfe for the comparable
2004 period.
INTEREST EXPENSE. Interest expense decreased $0.7 million (39%), to $1.1 million
for the second quarter of 2005 in comparison to the second quarter of 2004. The
decrease is primarily a result of reduction in long-term debt.
SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004
OPERATING REVENUES. Oil and natural gas revenues during the six months ended
June 30, 2005, decreased $2.0 million (2%) as compared to first half 2004
revenues due to a 16% decrease in production volumes primarily from natural
production declines, partially offset by a 17% increase in average commodity
prices on a natural gas equivalent basis. Our average daily production decreased
from 97 Mmcfe during the first six months of 2004 to 81 Mmcfe for the first six
months of 2005. 12.5 Mmcfe per day of the 15.5 Mmcfe per day difference was
related primarily to mechanical issues on two wells (SL 16049 #1 and Thibodeaux
#3) in the Ramos Complex area. Oil and natural gas production volume totaled
14,696 Mmcfe for the first six months of 2005, compared to 17,598 Mmcfe for the
comparable period of 2004.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the six months ended June 30, 2005 and
2004:
SIX MONTHS ENDED
JUNE 30, INCREASE
2005 2004 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 477 657 (27%)
Natural gas (MMcf) 11,833 13,656 (13%)
Mmcfe 14,696 17,598 (16%)
Average Sales Prices:
Oil (per Bbl) $ 32.70 $ 26.29 24%
Natural gas (per Mcf) 6.65 $ 5.78 15%
Mmcfe $ 6.42 $ 5.47 17%
Operating Revenues (000's):
Oil $15,603 $17,274 (10%)
Natural gas 78,615 78,931 ----
------- -------
Total Operating Revenues $94,218 $96,205 (2%)
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $3.0 million (53%) to $8.8 million during the first six months of
2005, compared to $5.8 million in 2004. On a unit basis, lease operating
expenses increased $0.27 per Mcfe to $0.60 per Mcfe for the first six months of
2005 from $0.33 per Mcfe for the first half of 2004. Oil and gas operating
expenses increased due to additional operating expenses associated with the
increase in wells and facilities in the Biloxi Marshlands project area, and to
increased workover related expenses, of approximately $1.8 million, primarily at
Weeks Island, Ramos and various offshore fields.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.3
million (7%) to $4.5 million for the first six months of 2005, compared to $4.8
million during the same period in 2004 primarily because of a decrease in oil
and natural gas production, partially offset by an increase in oil prices and a
higher
23
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 were
$0.208 per Mcf for natural gas for the first six months of 2005, an increase
from $0.171 per Mcf for the first half of 2004. On an equivalent unit of
production basis, severance and ad valorem taxes increased to $0.31 per Mcfe
from $0.27 per Mcfe for the comparable six-month period. Beginning July 1, 2005,
the revised severance tax rate for natural gas production in Louisiana over the
next twelve months will be $0.252 per Mcf. This will significantly increase the
amount of severance taxes being paid in future periods.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $1.6
million (3%) during the first half of 2005 to $50.7 million, from $49.1 million
for the same period of 2004. This was primarily the result of an increase in the
depletion rate as compared to the 2004 period, partially offset by the decline
in oil and natural gas production. During the second quarter of 2005, the
Company suspended operations to re-drill a well on its North Turtle Bayou
prospect after unsuccessful attempts to reestablish production from the well. As
a result, the Company revised its earlier reserve estimates associated with the
well resulting in a higher depletion and depreciation rate coupled with the
addition of costs related to unsuccessful wells drilled during 2005. On a unit
basis, depletion and depreciation expense increased by $0.66 per Mcfe, to $3.45
per Mcfe for the six months ended June 30, 2005, compared to $2.79 per Mcfe for
the same period in 2004.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$2.7 million to $9.4 million compared to $6.7 million for 2004. The increase was
primarily the result of increased professional services, accounting fees and
increased operating activities. On an equivalent unit of production basis,
general and administrative expenses increased $0.26 per Mcfe to $0.64 per Mcfe
for the first six months of 2005 compared to $0.38 per Mcfe for the comparable
2004 period.
INTEREST EXPENSE. Interest expense decreased $1.9 million (48%), to $2.1 million
for the first six months of 2005 in comparison to the first half of 2004. The
decrease is primarily a result of reduction in long-term debt.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first half of 2005, Meridian's capital expenditures
were internally financed with cash from operations. As of June 30, 2005, the
Company had a cash balance of $13.6 million and a working capital deficit of
$7.0 million. This deficit was made up primarily of a $5.6 million net current
liability associated with price risk management activities which will be offset
by future revenues. Management's strategy is to grow the Company by taking
advantage of the strong asset base built over the years and 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 $66.8 million for the
six months ended June 30, 2005, as compared to $74.3 million for the same period
in 2004. The decrease of $7.5 million was primarily due to a reduction in
liabilities in the first six months of 2005 over the first six months of 2004.
Net cash used in investing activities was $76.3 million during the six months
ended June 30, 2005, versus $59.7 million in the first six months of 2004. The
increase in capital expenditures of $16.6 million was primarily associated with
drilling and related activities in the Biloxi Marshlands project area and the
greater Ramos Complex.
Cash flows used in financing activities during the first six months of 2005 were
$1.1 million, compared to cash used in financing activities of $15.6 million
during the first six months of 2004. This reduction in cash used in financing
activities was primarily due to reduced preferred stock dividends coupled with
the reduction in debt repayments. With the preferred stock conversions in April
2005, the Company will see an annual $2.6 million reduction of dividend
payments.
CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit
facility to provide for a
24
four-year $200 million senior secured credit facility (the "Credit Facility")
with Fortis Capital Corp., as administrative agent, sole lead arranger and
bookrunner; Comerica Bank as syndication agent; and Union Bank of California as
documentation agent. Bank of Nova Scotia, Allied Irish Banks p.l.c., RZB Finance
LLC and Standard Bank PLC completed the syndication group. The initial borrowing
base under the Credit Facility is $130 million and it has been reaffirmed by the
syndication group effective April 30, 2005. As of June 30, 2005, outstanding
borrowings under the Credit Facility totaled $75.1 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company, have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and gas properties. In addition, the Company is required to deliver
to the lenders and maintain satisfactory title opinions covering not less than
70% of the present value of proved oil and gas properties. The Credit Facility
also contains other restrictive covenants, including, among other items,
maintenance of certain financial ratios, restrictions on cash dividends on
Common Stock and under certain circumstances Preferred Stock, limitations on the
redemption of Preferred Stock and an unqualified audit report on the Company's
consolidated financial statements, all of which the Company is in compliance.
Under the Credit Facility, 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 1.25% 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 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At June 30, 2005, the three-month LIBOR interest rate was
3.52%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
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 was convertible into shares of the Company's Common
Stock at a conversion price of $4.45 per share. Dividends were payable
semi-annually in cash or additional preferred stock. At the option of the
Company, one-third of the preferred shares could be forced to convert to Common
Stock if the closing price of the Company's Common Stock exceeded 150% of the
conversion price for 30 out of 40 consecutive trading days on the New York Stock
Exchange. The preferred stock was subject to redemption at the option of the
Company after March 2005, and mandatory redemption on March 31, 2009. During the
first six months of 2005, the Company completed the conversion of all of the
remaining outstanding shares of preferred stock to Common Stock, with $31.6
million of stated value being converted into approximately 7.1 million shares of
the Company's Common Stock.
OIL AND NATURAL GAS HEDGING ACTIVITIES. The Company addresses 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
25
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
$76.3 million. Although the Company plans to continue additional drilling during
the remainder of 2005, 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 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 2005 and 2006.
Based on internal projections, using its internal risked analysis of production
based on an expected capital expenditures program for 2005 of $139 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 and re-processing 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 approximately $67 million of 8.5%
Redeemable Convertible Preferred Stock and dividends were payable semi-annually.
A semi-annual cash dividend of $1.3 million was paid in January 2005. A final
cash dividend of $0.9 million was paid during the second quarter of 2005.
During the first six months of 2005, the Company completed the conversion of all
of the remaining outstanding shares of the 8.5% Redeemable Convertible Preferred
Stock to Common Stock, with $31.6 million of stated value being converted into
approximately 7.1 million shares of the Company's Common Stock. As a result of
these conversions in 2005, the Company will realize an annual cash savings of
approximately $2.6 million on the Preferred Stock dividends.
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, anticipated results from third party disputes and
litigation, expectations regarding 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
26
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 may be 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 available of
data and of engineering and geological interpretation and judgment. Reserve
estimates may be 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. 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 Fortis Capital
Corp. is presently scheduled for borrowing base redetermination dates on a
semi-annual basis with the next such redetermination scheduled for October 31,
2005. 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. Since interest charged on
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 $75.1 million remains borrowed under the Credit Agreement,
we estimate our annual interest expense will change by $0.75 million for each
100 basis point change in the applicable interest rates utilized under the
Credit Agreement.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter into swaps and other derivative contracts to hedge
the price risks associated with a portion of anticipated future oil and natural
gas production. While the use of hedging arrangements limits the downside risk
of adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. Meridian does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, the Company
would be exposed to price risk. Meridian has some risk of accounting loss since
the price received for the product at the actual physical delivery point may
differ from the prevailing price at the delivery point required for settlement
of the hedging transaction.
28
We have entered into certain swap agreements as summarized in the table below.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 42% of our proved developed natural gas production and 34% of our
proved developed oil production during the respective terms of the swap
agreements. The fair values of the hedges are based on the difference between
the strike price and the New York Mercantile Exchange future prices for the
applicable trading months.
Swap / Floor Ceiling Fair Value
Notional Price Price June 30, 2005
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ----------------- --------------
NATURAL GAS (MMBTU)
Jul 2005 Swap 130,000 $ 3.74 N/A $ (420)
Jul 2005 - Oct 2005 Swap 1,450,000 $ 6.34 N/A (1,061)
Jul 2005 - Oct 2005 Collar 1,450,000 $ 6.50 $ 7.90 35
--------
Total Natural Gas (1,446)
--------
CRUDE OIL (BBLS)
Jul 2005 Swap 38,000 $ 23.00 N/A (1,253)
Aug 2005 - Jul 2006 Collar 209,000 $ 37.50 $47.50 (2,597)
Aug 2005 - Jul 2006 Collar 48,000 $ 40.00 $50.00 (490)
--------
Total Crude Oil (4,340)
--------
$ (5,786)
========
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 2005.
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 2005 that could
significantly affect these controls.
29
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence and willful misconduct under certain
agreements concerning certain wells and property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of
Meridian's satisfying a prior adverse judgment in favor of Amoco Production
Company. Meridian has filed an answer denying Hawkins' claims and asserted a
counterclaim for attorney's fees, court costs and other expenses, and for
declaratory relief that Meridian is entitled to retain the amounts that it had
been paid by Hawkins. The Company has not provided any amount for this matter in
its financial statements at June 30, 2005.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning the Weeks
Island, Gibson, Bayou Pigeon, West Lake Verret and White Castle 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. The Company has not
provided any amount for these matters in its financial statements at June 30,
2005.
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed 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 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of shareholders held on June 23, 2005, the Company's
shareholders elected three Class III Directors. The following summarizes the
number of votes for and against each nominee.
Broker
Nominee For Withheld Non-Vote
--------------------- ---------- --------- ---------
Joseph A. Reeves, Jr. 77,798,713 1,973,306 6,795,646
Michael J. Mayell 77,798,713 1,973,306 6,795,646
Fenner R. Weller, Jr. 77,798,713 1,973,306 6,795,646
The terms of the Class I directors (David W. Tauber, John B. Simmons and James
R. Montague) and the Class II directors (E.L. Henry, Joe E. Kares and Gary A.
Messersmith) continued after the meeting.
30
ITEM 6. 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.
31
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, 2005 By: /s/ LLOYD V. DELANO
------------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
32
INDEX TO 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.