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, 2006
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
incorporation or organization) Identification No.)
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 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one)
Large Accelerated Filer [ ] Accelerated Filer [X] Non-Accelerated Filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Number of shares of common stock outstanding at August 3, 2006: 87,037,049
Page 1 of 32
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, 2006 and 2005 3
Consolidated Balance Sheets as of June 30, 2006 (unaudited)
and December 31, 2005 4
Consolidated Statements of Cash Flows (unaudited) for the
Six Months Ended June 30, 2006 and 2005 6
Consolidated Statements of Stockholders' Equity (unaudited) for
the Six Months Ended June 30, 2006 and 2005 7
Consolidated Statements of Comprehensive Income (Loss)
(unaudited) for the Three Months and Six Months Ended June 30,
2006 and 2005 8
Notes to Consolidated Financial Statements (unaudited) 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures about Market Risk 27
Item 4. Controls and Procedures 29
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 30
Item 1a. Risk Factors 30
Item 4. Submission of Matters to a Vote to 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,
------------------ ------------------
2006 2005 2006 2005
------- -------- -------- -------
REVENUES:
Oil and natural gas $45,101 $44,086 $102,928 $94,218
Price risk management activities 1,003 (168) 363 (460)
Interest and other 436 185 755 389
------- ------- -------- -------
46,540 44,103 104,046 94,147
------- ------- -------- -------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 5,011 4,109 9,564 8,792
Severance and ad valorem taxes 2,610 1,866 5,345 4,498
Depletion and depreciation 27,671 25,405 57,170 50,727
General and administrative 4,405 4,371 9,516 9,384
Accretion expense 319 275 620 526
Hurricane damage repairs 404 -- 2,403 --
------- ------- -------- -------
40,420 36,026 84,618 73,927
------- ------- -------- -------
EARNINGS BEFORE INTEREST AND INCOME TAXES 6,120 8,077 19,428 20,220
------- ------- -------- -------
OTHER EXPENSES:
Interest expense 1,489 1,097 2,867 2,082
------- ------- -------- -------
EARNINGS BEFORE INCOME TAXES 4,631 6,980 16,561 18,138
------- ------- -------- -------
INCOME TAXES:
Current 197 (333) 368 257
Deferred 1,591 3,016 6,019 6,726
------- ------- -------- -------
1,788 2,683 6,387 6,983
------- ------- -------- -------
NET EARNINGS: 2,843 4,297 10,174 11,155
Dividends on preferred stock -- 171 -- 902
------- ------- -------- -------
NET EARNINGS APPLICABLE
TO COMMON STOCKHOLDERS $ 2,843 $ 4,126 $ 10,174 $10,253
======= ======= ======== =======
NET EARNINGS PER SHARE:
Basic $ 0.03 $ 0.05 $ 0.12 $ 0.12
Diluted $ 0.03 $ 0.05 $ 0.11 $ 0.12
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 86,950 85,277 86,900 82,291
Diluted 92,140 90,770 92,346 87,914
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
JUNE 30, DECEMBER 31,
2006 2005
----------- ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 39,334 $ 23,265
Restricted cash 1,253 1,234
Accounts receivable, less allowance for doubtful accounts of
$232 [2006] and $242 [2005] 26,927 41,188
Prepaid expenses and other 7,205 1,294
Assets from price risk management activities 6,592 528
Deferred tax asset -- 1,150
---------- ----------
Total current assets 81,311 68,659
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$42,243 [2006] and $26,623 [2005] not subject to depletion) 1,566,322 1,512,036
Land 48 48
Equipment 6,784 6,540
---------- ----------
1,573,154 1,518,624
Less accumulated depletion and depreciation 1,089,761 1,032,595
---------- ----------
Total property and equipment, net 483,393 486,029
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 167 235
Deferred tax asset 109 --
Other 658 879
---------- ----------
Total other assets 934 1,114
---------- ----------
TOTAL ASSETS $ 565,638 $ 555,802
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
JUNE 30, DECEMBER 31,
2006 2005
----------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 5,786 $ 7,595
Revenues and royalties payable 7,350 9,149
Due to affiliates 2,813 4,638
Notes payable 5,957 1,103
Accrued liabilities 19,136 22,272
Liabilities from price risk management activities 4,700 3,977
Asset retirement obligations 2,808 2,879
Deferred income taxes 668 --
Current income taxes payable -- 108
--------- ---------
Total current liabilities 49,218 51,721
--------- ---------
LONG-TERM DEBT 65,000 75,000
--------- ---------
OTHER:
Deferred income taxes 48,076 41,967
Liabilities from price risk management activities 480 464
Asset retirement obligations 9,989 9,085
--------- ---------
58,545 51,516
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 5)
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
87,024,547 [2006] and 86,817,658 [2005] issued) 905 900
Additional paid-in capital 526,528 524,692
Accumulated deficit (135,221) (145,395)
Accumulated other comprehensive income (loss) 1,037 (2,314)
Unamortized deferred compensation (374) (318)
--------- ---------
Total stockholders' equity 392,875 377,565
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 565,638 $ 555,802
========= =========
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,
-------------------------
2006 2005
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 10,174 $ 11,155
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depletion and depreciation 57,170 50,727
Amortization of other assets 221 216
Non-cash compensation 1,197 939
Non-cash price risk management activities (363) 460
Accretion expense 620 526
Deferred income taxes 6,019 6,726
Changes in assets and liabilities:
Restricted cash (19) (2,002)
Accounts receivable 14,261 6,517
Prepaid expenses and other (5,911) (1,601)
Due to affiliates (1,825) (403)
Accounts payable (1,809) (222)
Revenues and royalties payable (1,799) (1,302)
Accrued liabilities and other (2,400) (4,973)
-------- --------
Net cash provided by operating activities 75,536 66,763
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (65,062) (76,259)
Proceeds from (settlements on) sale of property 10,741 (55)
-------- --------
Net cash used in investing activities (54,321) (76,314)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt (10,000) --
Reductions in notes payable (3,065) (1,305)
Proceeds from notes payable 7,919 2,443
Issuance of stock/exercise of stock options, net -- 13
Preferred dividends -- (2,166)
Additions to deferred loan costs -- (93)
-------- --------
Net cash used in financing activities (5,146) (1,108)
-------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS 16,069 (10,659)
Cash and cash equivalents at beginning of period 23,265 24,297
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 39,334 $ 13,638
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ -- $(30,625)
Issuance of shares for settlement of accrued liabilities $ (588) $ (1,484)
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SIX MONTHS ENDED JUNE 30, 2006 AND 2005
(in thousands)
(unaudited)
Accumulated
Common Stock Additional Other Unamortized
------------------ Paid-In Accumulated Comprehensive Deferred
Shares Par Value Capital (Deficit) Income(Loss) Compensation Total
------ --------- ---------- ----------- ------------- ------------ --------
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) --
Company's 401(k) plan contribution 16 -- 85 -- -- -- 85
Exercise of stock options 49 -- 163 -- -- -- 163
Compensation expense -- -- -- -- -- 854 854
Accum. other comprehensive loss -- -- -- -- (1,970) -- (1,970)
Issuance for conversion of pref stock 7,099 71 30,554 -- -- -- 30,625
Issuance of shares - 2004 stock offer -- -- (150) -- -- -- (150)
Issuance of shares as compensation 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
====== ==== ======== ========= ======= ===== ========
Balance, December 31, 2005 86,818 $900 $524,692 $(145,395) $(2,314) $(318) $377,565
Issuance of rights to common stock -- 2 899 -- -- (901) --
Company's 401(k) plan contribution 45 1 184 -- -- -- 185
Stock-based compensation-FAS123R -- -- 167 -- -- -- 167
Compensation expense -- -- -- -- -- 845 845
Accuml other comprehensive income -- -- -- -- 3,351 -- 3,351
Issuance of shares as compensation 162 2 586 -- -- -- 588
Net earnings -- -- -- 10,174 -- -- 10,174
------ ---- -------- --------- ------- ----- --------
Balance, June 30, 2006 87,025 $905 $526,528 $(135,221) $ 1,037 $(374) $392,875
====== ==== ======== ========= ======= ===== ========
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 Six Months Ended
Ended June 30, June 30,
---------------- -----------------
2006 2005 2006 2005
------ ------- ------- -------
Net earnings applicable to common stockholders $2,843 $ 4,126 $10,174 $10,253
Other comprehensive income (loss), net of tax, for unrealized losses from
hedging activities:
Unrealized holding gains (losses) arising during period (1) 1,761 2,280 2,605 (6,405)
Reclassification adjustments on settlement of contracts (2) (14) 3,223 746 4,435
------ ------- ------- -------
1,747 $ 5,503 3,351 (1,970)
------ ------- ------- -------
Total comprehensive income $4,590 $ 9,629 $13,525 $ 8,283
====== ======= ======= =======
(1) net of income tax (expense) benefit $ (948) $(1,227) $(1,403) $ 3,449
(2) net of income tax (expense) benefit $ 7 $(1,736) $ (401) $(2,388)
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, 2005, as filed with the Securities and Exchange Commission.
The financial statements included herein as of June 30, 2006, and for the three
and six month periods ended June 30, 2006 and 2005, 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 accrued liabilities on the Company's balance sheets as of
June 30, 2006 and December 31, 2005 (thousands of dollars):
JUNE 30, DECEMBER 31,
2006 2005
-------- ------------
Capital expenditures $12,334 $12,853
Operating expenses/taxes 3,235 2,794
Hurricane damage repairs 365 2,717
Compensation 1,550 1,949
Interest 499 503
Other 1,153 1,456
------- -------
TOTAL $19,136 $22,272
======= =======
3. DEBT
CREDIT FACILITY. On December 23, 2004, the Company amended its 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 was $130 million and was
reaffirmed by the syndication group effective April 30, 2006. Repayments of $10
million were made during the second quarter of 2006 resulting in an outstanding
balance of $65 million on June 30, 2006.
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. The determination of the borrowing base is subject to a
number of factors, including quantities of proved oil and
9
gas reserves, the bank's commodity price assumptions and other various factors
unique to each member bank. The Company's lenders can redetermine the borrowing
base to a lower level than the current borrowing base if they determine that the
oil and natural gas reserves, at the time of redetermination, are inadequate to
support the borrowing base then in effect.
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 natural 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 natural 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 annual consolidated financial statements. As of June 30, 2006,
management believes that the Company is in compliance with all of the covenants
of the Credit Facility.
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, 2006, the three-month LIBOR interest rate was
5.48%. 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
In 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 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, 2006.
TITLE/LEASE DISPUTES. Title and lease disputes arise due to various events that
have occurred in the various states in which the Company operates. These
disputes are usually small and could lead to the Company over- or under-stating
reserves when a final resolution to the title dispute is made.
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
10
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, in certain instances, has
indemnified third parties from the claims made in these lawsuits. The Company
has not provided any amount for these matters in its financial statements at
June 30, 2006.
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.
INSURANCE.
HURRICANE INSURANCE. Preliminary discussions with the Company's insurance
provider indicate that there is uncertainty regarding full reimbursement of $1.5
million of hurricane debris removal costs. This $1.5 million is on the Company's
balance sheet in accounts receivable. The Company believes that the full $1.5
million expended for debris removal should be reimbursed and continues to pursue
that result.
11
6. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted net earnings
per share (in thousands, except per share):
THREE MONTHS
ENDED JUNE 30,
-----------------
2006 2005
------- -------
Numerator:
Net earnings applicable to common stockholders $ 2,843 $ 4,126
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 86,950 85,277
Effect of potentially dilutive common shares:
Warrants 5,079 4,746
Employee and director stock options 111 747
------- -------
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions 92,140 90,770
======= =======
Basic earnings per share $ 0.03 $ 0.05
======= =======
Diluted earnings per share $ 0.03 $ 0.05
======= =======
SIX MONTHS
ENDED JUNE 30,
-----------------
2006 2005
------- -------
Numerator:
Net earnings applicable to common stockholders $10,174 $10,253
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 86,900 82,291
Effect of potentially dilutive common shares:
Warrants 5,027 4,641
Employee and director stock options 419 982
------- -------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 92,346 87,914
======= =======
Basic earnings per share $ 0.12 $ 0.12
======= =======
Diluted earnings per share $ 0.11 $ 0.12
======= =======
7. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments with value
fluctuations that correlate strongly with the underlying commodity being hedged.
From time to time, we may enter into 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
12
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
derivative contracts. These contracts allow the Company to predict with greater
certainty the 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
contracts have been designated as cash flow hedges as provided by Statement of
Financial Accounting Standards ("SFAS") No. 133 and after-tax changes in fair
value, excluding changes due to ineffectiveness, are recorded in other
comprehensive income until earnings are affected by the variability in cash
flows of the designated hedged item. Changes in fair value resulting from hedge
ineffectiveness are reported in the consolidated statement of operations as a
component of revenues. The Company recognized gains (losses) related to hedge
ineffectiveness of $1.0 million and ($0.2) million during the three months ended
June 30, 2006, and June 30, 2005, respectively, and $0.4 million and ($0.5)
million during the six months ended June 30, 2006, and June 30, 2005,
respectively.
At June 30, 2006, the Company's oil and natural gas derivatives had an
unrealized gain of $1.6 million ($1.0 million net of tax) which is recorded in
Accumulated Other Comprehensive Income (Loss) on the Company's consolidated
balance sheet. Based upon June 30, 2006 oil and natural gas commodity prices,
approximately $1.9 million of the gain deferred in other comprehensive income
could potentially increase gross revenues over the next twelve months. As of
June 30, 2006, the derivative contracts expire at various dates through July 31,
2008.
Net settlements under these contracts (reduced) increased oil and natural gas
revenues by $21,000 and ($4,959,000) for the three months ended June 30, 2006
and 2005, respectively, and by ($1,147,000) and ($6,823,000) for the six months
ended June 30, 2006 and 2005, respectively, as a result of hedging transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. As of June 30, 2006, the positions hedged
approximately 34% of the estimated proved developed natural gas production and
19% of the estimated proved developed oil production during the respective terms
of the hedging agreements. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
The fair value of the Company's hedging agreements is recorded on the
consolidated balance sheet as separately identified assets or liabilities. The
estimated fair value of the hedging agreements as of June 30, 2006, is provided
below:
13
Estimated
Fair Value
Asset (Liability)
Notional Floor Price Ceiling Price June 30, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------- -----------------
NATURAL GAS (MMBTU)
July 2006 - Oct 2006 Collar 600,000 $ 8.00 $14.50 $ 1,141
July 2006 - May 2007 Collar 4,400,000 $ 8.00 $10.60 2,220
-------
Total Natural Gas 3,361
-------
CRUDE OIL (BBLS)
July 2006 Collar 14,000 $37.50 $47.50 (373)
July 2006 Collar 4,000 $40.00 $50.00 (96)
Aug 2006 - Jul 2007 Collar 168,000 $50.00 $74.00 (1,096)
Aug 2007 - Apr 2008 Collar 54,000 $60.00 $82.00 (177)
May 2008 - Jul 2008 Collar 15,000 $60.00 $82.00 (40)
-------
Total Crude Oil (1,782)
-------
$ 1,579
=======
The above excludes hedges entered into after June 30, 2006; see Note 12,
Subsequent Event, for additional information.
8. STOCK-BASED COMPENSATION
In December 2004, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 123R which is a replacement statement to SFAS No. 123 entitled "Share-Based
Payment." This statement also amends SFAS No. 95. 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 eliminates the ability to account for share-based compensation
transactions using Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees," and generally requires instead that such
transactions be accounted for using a fair-value-based method. The Company
adopted the provisions of SFAS No. 123R on January 1, 2006, using the modified
prospective method.
Compensation expense is recorded for stock option awards over the requisite
vesting periods based upon the market value on the date of the grant.
Stock-based compensation expense related to SFAS No. 123R of approximately
$85,000 and $167,000 was recorded in the three months and six months ended June
30, 2006, respectively. No stock-based compensation expense related to SFAS No.
123R was recorded in the three or six month periods ended June 30, 2005.
The following is a pro-forma 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).
14
Three Months Six Months
Ended June 30, Ended June 30,
2005 2005
-------------- --------------
Net earnings applicable to common
stockholders as reported $4,126 $10,253
Stock-based compensation (expense)
benefit determined under fair value
method for all awards, net of tax (40) (98)
------ -------
Net earnings applicable to common
stockholders pro forma $4,086 $10,155
====== =======
Basic earnings per share:
As reported $ 0.05 $ 0.12
Pro forma $ 0.05 $ 0.12
Diluted earnings per share:
As reported $ 0.05 $ 0.12
Pro forma $ 0.05 $ 0.12
9. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS No. 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 of our oil and natural gas properties,
excluding salvage values.
The following table describes the change in the Company's asset retirement
obligations for the six months ended June 30, 2006, and for the year ended
December 31, 2005 (thousands of dollars):
Asset retirement obligation at December 31, 2004 $ 9,624
Additional retirement obligations recorded in 2005 883
Settlements during 2005 (182)
Revisions to estimates during 2005 519
Accretion expense for 2005 1,120
-------
Asset retirement obligation at December 31, 2005 11,964
Additional retirement obligations recorded in 2006 109
Revisions to estimates during 2006 104
Accretion expense for 2006 620
-------
Asset retirement obligation at June 30, 2006 $12,797
=======
The Company's revisions to estimates represent changes to the expected amount
and timing of payments to settle the asset retirement obligations. These changes
primarily result from obtaining new information about the timing of our
obligations to plug the natural gas and oil wells and costs to do so.
15
10. LEASE OBLIGATIONS
In April 2006, the Company completed negotiations for an amendment to the
current office building lease agreement that extends the current office lease
until September 30, 2011. The base rental payments will be $1.7 million in 2007
and 2008, $1.8 million in 2009, $2.0 million in 2010 and $1.6 million in 2011.
11. NEW ACCOUNTING PRONOUNCEMENTS
In July 2006, the FASB issued FASB Interpretation No. 48 ("FIN 48"), "Accounting
for Uncertainty in Income Taxes - and interpretation of SFAS No. 109." FIN 48
clarifies the accounting for uncertainty in income taxes recognized in an
enterprise's financial statements in accordance with SFAS No. 109, Accounting
for Income Taxes. FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return. FIN 48 also provides
guidance on recognition, classification, interest and penalties, accounting in
interim periods, disclosure, and transition. FIN 48 is effective for fiscal
years beginning after December 15, 2006. Implementation of FIN 48 is not
expected to have a material financial statement impact on the Company.
12. SUBSEQUENT EVENT
During July and August 2006, the Company entered into hedging contracts to hedge
a portion of its oil production for 2006 - 2008. 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 hedged
volumes. The floor price represents the lowest price the Company will receive
for the hedged 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 during each respective month. The Notional Amount is equal to
the total net volumetric hedge position of the Company during the periods
presented. These hedge contracts, combined with those discussed in Note 7, hedge
approximately 29% of the estimated proved developed oil production during the
respective terms of the hedging agreements. The following table summarizes the
contracted volumes and prices for the costless collars.
Notional Floor Price Ceiling Price
Amount ($ per unit) ($ per unit)
-------- ------------ -------------
CRUDE OIL (BBLS)
Sept 2006 - July 2007 44,000 $60.00 $96.10
Aug 2007 - July 2008 52,000 $65.00 $93.15
Aug 2007 - July 2008 40,000 $70.00 $87.40
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL.
Tremendous strides toward growth have been made during the course of the last
twelve months. Management has recently moved on a series of transactions that we
believe sets the stage for the return of the Company to near- and long-term
incremental growth. We first expanded our vision beyond the conventional Gulf
Coast region, and established significant acreage positions in seven distinct
regions which we believe will provide the Company with a diversity of lower-risk
exploration, exploitation and development project inventory--an inventory that
will generate multiple wells, repeatable drilling locations well beyond 2006,
adding longer-lived, longer-styled reserves as a complement to our traditional
higher cash-flow properties located in the Gulf Coast region.
Each of the newly-acquired positions and joint venture associations was selected
for specific reasons after a very measured approach and performing thorough
technical studies. The terms, conditions and lease positions we likewise
examined in light of the Company's capital position relative to its ability to
acquire the necessary equipment to drill and hold the acreage positions without
risking the loss of leases or incurring additional costs unrelated to the
development of reserves, cash flows, or expected returns on our respective
investments.
Following is a brief description and discussion of each of the areas we have
selected and successfully secured initial positions within - areas where we
anticipate the Company's return to growth will begin.
During the first six months of 2006, the Company continued to reposition and
expand its asset base through a combination of newly formed joint ventures and
acquisitions in six specific regions of the domestic United States. Below is a
recapitulation of the joint ventures and acquisitions that have been concluded
or are nearly complete.
JOINT VENTURES AND ACQUISITIONS GROWTH STEPS
EAST TEXAS AUSTIN CHALK/WOODBINE PLAY. A Joint Venture and Exploration Agreement
was initially entered into during 2005 that originally comprised approximately
7,000 gross acres on which four wells were drilled during 2006. Currently,
negotiations are under way to expand the Company's acreage position within this
area to over 30,000 acres. Much of the acreage is offset to the Double A Wells
Woodbine field and more recent wells that have been reported as testing the
Austin Chalk section at rates as much as 18 million cubic feet ("Mmcf") of
natural gas per day and as much as 2,000 barrels of condensate per day.
Currently, the Company has one rig under contract that is drilling horizontal
laterals on the first of three Austin Chalk wells. Meridian is currently working
to secure a second rig before the end of the year to drill the horizontal Austin
Chalk laterals needed for the completion of two previously drilled vertical
wells. The fourth well, a Woodbine test, was recently brought online and is
scheduled for fracture stimulation in September. Additionally, the Company is in
negotiations for the possible construction and purchase of two rigs for its own
account to accelerate the development of the Company's new acreage positions and
other plays. Meridian owns working interest positions ranging between 25% and
100% and is the operator for the wells.
NORTH TEXAS, PALO DURO BASIN PLAY. A Joint Venture and Exploration Agreement and
acquisition was closed during the first quarter 2006 giving the Company between
50% and 75% working interest positions in approximately 35,000 gross acres in
Floyd and Motley Counties, Texas. The primary target formation is the
Pennsylvanian Shale between 8,000 and 10,000 feet with average shale thickness
approximating 1,000 feet. Several operators in the basin are in various stages
of drilling and testing optimal completion techniques for wells in the area. The
Company is currently developing its operational plan for the basin based on the
results of offset operations and other intelligence gathered over time. Meridian
is the operator.
17
NEW ALBANY, ILLINOIS BASIN PLAY. A Joint Venture and Exploration Agreement was
entered into during March 2006 whereby the Company acquired approximately 16,000
gross acres. Since that time, the Company has been in the field acquiring leases
and currently has agreements for an additional 9,000 acres for a total of
approximately 25,000 acres. Depending on the level of success in the initial
stages of drilling and testing in the area, the Company has plans to continue
leasing activities to expand its position in this region to over 140,000 acres.
Targeted formations are the New Albany Shale at depths generally between 2,000
feet and 5,000 feet with an average thickness of 300 feet. Plans are to initiate
drilling activities during 2006 depending on rig availability. Working interest
is anticipated to be between 75% and 100% with Meridian as operator.
FAR WEST TEXAS, DELAWARE BASIN. A Joint Venture and Exploration Agreement was
entered into during April 2006, with the acquisition of a 50% working interest
in approximately 75,000 gross acres in Culbertson and Hudspeth Counties, Texas.
Targeted formations are the Barnett and Woodford Shale sections which range
between 5,500 and 8,500 feet. Current plans are to acquire several 2-D seismic
lines over portions of the acreage and to initiate drilling operations during
late 2006 or early 2007. Meridian's joint venture partner will operate the
project.
NORTH CENTRAL OKLAHOMA, SOONER TREND, HUNTON/WOODFORD PLAY. Exploration/
exploitation acreage was recently purchased in the producing trend of the
Hunton/Woodford formations play. Depths in this play range between 7,000 and
8,000 feet. The Company owns approximately 10,000 acres with plans to expand its
position. The Company currently owns a 100% working interest and will operate
the field. It is anticipated that the initial drilling operations will begin
prior to year-end.
GULF COAST REGIONS OF TEXAS AND SOUTH LOUISIANA. Acquisition and purchase
agreements in principal are in final and other closing stages to expand the
Company's acreage holdings and joint venture participation positions in numerous
plays and prospects in the Company's core exploration and producing regions.
Four wells are being readied for drilling in the regions during the last half of
2006. Subject to rig availability, additional prospects could also be drilled
before the end of the year.
UPDATE ON CURRENT OPERATIONS
WEEKS ISLAND FIELD. The Company recently brought online production from the
previously announced Goodrich-Cocke No. 4 development well located in Iberia
Parish, Louisiana. The well was drilled to a measured depth of approximately
8,100 feet and logged approximately 91 feet of gross gas pay in the Miocene
"BF4" sand section. The well was tested through a total of 24 feet of
perforations in three separate intervals. The well is currently producing at a
gross rate of 5.3 Mmcfe/d (2.7 net).
The Company is currently drilling the J.A. Smith well on the Y-Not prospect
located in the Weeks Island field in Iberia Parish, Louisiana. The well is being
drilled to a total depth of approximately 16,000 feet to reach the targeted sand
which is the Lower Miocene Planulina Sand (also known as the "Y" sand). The
well, which had to be sidetracked, is currently at a measured depth of
approximately 14,000 feet.
RAMOS COMPLEX AREA. The Company recently re-completed the CL&F E-1 well on its
Turtle Shell prospect in the Cib Op 3 sand interval. The 10 feet of perforations
were made between 14,020 and 14,030 feet in the sand. Flowing tubing pressure
was measured at 4,200 pounds per square inch ("psi") through a 13/64ths-inch
choke. The well is currently producing at a rate of 5.4 Mmcfe/d (3.2 net).
BILOXI MARSHLAND. The Biloxi Marshland ("BML") 28-1 well was brought back online
after repairs were completed to the well head damaged by Hurricane Katrina.
Repairs were delayed due to potential well control issues and procurement of
proper equipment to handle such issues. The well is currently producing at a
rate of 1.4 Mmcfe/d (0.9 net).
18
The Apache La. Minerals No. 1 well on its Bayou Gentilly prospect located on the
southern edge of the Biloxi Marshland area was completed in August of last year.
The well was tested from the Cris "I" sand interval at a gross daily flow rate
as high as 5.9 Mmcf/d and 654 barrels of condensate (6.4 Mmcfe/d net). A new
line and production facilities have recently been completed. The Company is
currently waiting for the pipeline operator to conduct a hot tap, shortly after
which the well will be flowing into sales. The Company expects this to take
place in the third quarter. The Company owns a 92% working interest in this
well.
OTHER OUTSIDE-OPERATED ACTIVITY
GIBSON-HUMPHREYS FIELD. As previously announced, the Westervelt No. 2 well on
the Gumbo prospect was drilled to a target depth of 19,400 feet and encountered
pay in the Rob L sand interval. Meridian owns a 2.7% overriding royalty interest
in the well by virtue of land positions. Denbury Resources is the operator of
the well and is now in the process of completing the well.
THORNWELL FIELD. The previously announced Abshire No. 33-1 well was drilled by
Denbury Resources to a total depth of 11,350 feet and logged pay in the Bol Perc
sands. The operator has completed the well and is currently producing at a gross
rate of 5.1 Mmcfe/d. Meridian owns a 12.3% non-operated working interest in the
well (7.9% net).
PRODUCTION
Production for the first half of 2006 was in line with expectations, albeit
slightly lower in the second quarter when compared to the first quarter. The
primary focus during the period was in the Company's East Texas Austin
Chalk/Woodbine play where we drilled four wells utilizing rigs with short-term
"windows." Four of the four wells indicated positive log results in the Austin
Chalk section, similar in character to nearby offset wells that have tested at
rates of 3 Mmcfd to 18 Mmcfd. Unfortunately, due to the short-term nature of the
rig contracts, we were only able to drill the laterals required to complete the
Austin Chalk formation on one well, the BSM #1. This well's first lateral has
been drilled, and the second, or northerly, lateral is currently under way. The
Company is awaiting the return of rig equipment, currently scheduled to occur
late in the third or early in the fourth quarter, to complete lateral drilling
on two other wells in this play.
The Company has entered into an agreement, in principal, to purchase two rigs
that will be under the sole control of Meridian. Delays in securing drilling
equipment has resulted in delays with respect to our expected reserves and
production, both of which drive our cash flow, earnings, and finding and
development costs. Production rates are anticipated to show incremental
increases as the Company completes the drilling of the Austin Chalk wells, and
completes the tie-in of the Bayou Gentilly Apache La. Minerals No. 1 well which
is expected to begin during the third quarter.
Additional drilling projects scheduled during the second half of 2006, if
successful, will be additive to this effort. Cash flows from operating
activities were $27 million for the second quarter of 2006, compared to $37
million for the comparable period of 2005, and $75 million for the first six
months of 2006, compared to $67 million for the first six months of 2005. Cash
flows supported the Company's capital expenditure program set for approximately
$132 million for the year.
Concurrently, the Company's liquidity and low debt to cap ratio (14%) improved
during the first six months of 2006, as we continued to fund our capital program
from cash flow and pay down senior bank debt, currently at $65 million.
We believe that we have made significant progress on all fronts of our plan to
reposition the Company to include a more balanced exploration/exploitation
portfolio that is achievable both in the near- and long-term,
19
within reasonable bounds of risk when compared to a singular, one-dimensional
strategy of one property set or region.
OTHER CONDITIONS.
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, 2006,
was $56.01 per barrel compared to $31.14 per barrel for the three months ended
June 30, 2005, and $49.23 per barrel for the three months ended March 31, 2006.
Our average natural gas price (after adjustments for hedging activities) for the
three months ended June 30, 2006, was $7.29 per Mcf compared to $6.63 per Mcf
for the three months ended June 30, 2005, and $9.20 per Mcf for the three months
ended March 31, 2006. 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, 2005, for further discussion.
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2006 COMPARED TO THREE MONTHS ENDED JUNE 30, 2005
OPERATING REVENUES. Second quarter 2006 oil and natural gas revenues, which
include oil and natural gas hedging activities (see Note 7 of Notes to
Consolidated Financial Statements), increased $1.0 million (2%) as compared to
second quarter 2005 revenues due to a 21% increase in average commodity prices
on a natural gas equivalent basis, partially offset by a 16% decrease in
production volumes. Oil and natural gas production volume totaled 5,850 Mmcfe
for the second quarter of 2006 compared to 6,931 Mmcfe for the comparable period
of 2005. Our average daily production decreased from 76 Mmcfe during the second
quarter of 2005 to 64 Mmcfe for the second quarter of 2006. The variance in
average daily production volumes between the two periods is due in part to
mechanical issues caused by the 2005 hurricanes on the BML 1-2 well and the BML
28-1 well. Production from the BML 28-1 well was restored during June 2006 at
rates comparable to pre-storm levels. Production from the BML 1-2 well has been
deferred until the proper rig can be secured to complete the re-drilling of the
well. Additional variance differences can be attributed to natural production
declines offset by new discoveries brought on between the comparable periods.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended June 30, 2006 and
2005:
20
THREE MONTHS ENDED
JUNE 30,
------------------ INCREASE
2006 2005 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 199 217 (8%)
Natural gas (MMcf) 4,657 5,630 (17%)
Mmcfe 5,850 6,931 (16%)
Average Sales Prices:
Oil (per Bbl) $ 56.01 $ 31.14 80%
Natural gas (per Mcf) $ 7.29 $ 6.63 10%
Mmcfe $ 7.71 $ 6.36 21%
Operating Revenues (000's):
Oil $11,145 $ 6,757 65%
Natural gas 33,956 37,329 (9%)
------- -------
Total Operating Revenues $45,101 $44,086 2%
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $0.9 million (22%) to $5.0 million during the second quarter of 2006,
compared to $4.1 million in 2005. On a unit basis, lease operating expenses
increased $0.27 per Mcfe to $0.86 per Mcfe for the second quarter of 2006 from
$0.59 per Mcfe for the second quarter of 2005. Oil and natural gas operating
expenses increased primarily due to significantly higher insurance costs. The
effect of last year's hurricane season resulted in an insurance rate increase
for the Company. Effective May 1, 2006, the rate increased by approximately 480%
or $0.7 million during the second quarter of 2006. The increase in the per Mcfe
rate was primarily attributable to the lower production between the two
corresponding periods.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $0.7
million (40%) to $2.6 million for the second quarter of 2006, compared to $1.9
million during the same period in 2005 primarily because of an increase in oil
prices and a higher natural gas tax rate, partially offset by the previously
discussed decline in production. 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 $0.252
per Mcf for natural gas, an increase from $0.208 per Mcf for the first half of
2006. On an equivalent unit of production basis, severance and ad valorem taxes
increased to $0.45 per Mcfe from $0.27 per Mcfe for the comparable three-month
period. Beginning July 1, 2006, the revised severance tax rate for natural gas
production in Louisiana over the next twelve months will be $0.373 per Mcf. This
will significantly increase the amount of severance taxes being paid in future
periods.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $2.3
million (9%) during the second quarter of 2006 to $27.7 million, from $25.4
million for the same period of 2005. This was primarily the result of an
increase in the depletion rate as compared to the 2005 period, partially offset
by the decrease in oil and natural gas production. On a unit basis, depletion
and depreciation expense increased by $1.06 per Mcfe, to $4.73 per Mcfe for the
three months ended June 30, 2006, compared to $3.67 per Mcfe for the same period
in 2005, primarily due to the impact of negative reserve revisions during 2005
and the rising costs in the industry for current and projected capital
expenditures.
21
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was $4.4
million for 2006 and for 2005. On an equivalent unit of production basis,
general and administrative expenses increased $0.12 per Mcfe to $0.75 per Mcfe
for the second quarter of 2006 compared to $0.63 per Mcfe for the comparable
2005 period primarily due to lower production rates between the periods.
Stock-based compensation expense related to SFAS No. 123R of approximately
$85,000 was recorded in the three months ended June 30, 2006. No stock-based
compensation related to SFAS No. 123R expense was recorded in the three month
period ended June 30, 2005.
HURRICANE DAMAGE REPAIRS. This expense of $0.4 million is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
costs in excess of insured values.
INTEREST EXPENSE. Interest expense increased $0.4 million (36%), to $1.5 million
for the second quarter of 2006 in comparison to the second quarter of 2005. The
increase is primarily a result of increased interest rates.
SIX MONTHS ENDED JUNE 30, 2006 COMPARED TO SIX MONTHS ENDED JUNE 30, 2005
OPERATING REVENUES. Oil and natural gas revenues during the six months ended
June 30, 2006, increased $8.7 million (9%) as compared to first half 2005
revenues due to a 31% increase in average commodity prices on a natural gas
equivalent basis, partially offset by a 16% decrease in production volumes. The
variance in average daily production volumes between the two periods is due in
part to mechanical issues caused by the 2005 hurricanes on the BML 1-2 well and
the BML 28-1 well. The BML 28-1 well was returned to production during June 2006
at rates comparable to pre-storm levels. Production from the BML 1-2 well has
been deferred until the proper rig can be secured to complete the re-drilling of
the well. Additional variance differences can be attributed to natural
production declines partially offset by new discoveries brought on between the
comparable periods. Our average daily production decreased from 81 Mmcfe during
the first six months of 2005 to 68 Mmcfe for the first six months of 2006. Oil
and natural gas production volume totaled 12,282 Mmcfe for the first six months
of 2006, compared to 14,696 Mmcfe for the comparable period of 2005.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the six months ended June 2006 and 2005:
SIX MONTHS ENDED
JUNE 30,
------------------ INCREASE
2006 2005 (DECREASE)
-------- ------- ----------
Production Volumes:
Oil (Mbbl) 423 477 (11%)
Natural gas (MMcf) 9,744 11,833 (18%)
Mmcfe 12,282 14,696 (16%)
Average Sales Prices:
Oil (per Bbl) $ 52.43 $ 32.70 60%
Natural gas (per Mcf) $ 8.29 $ 6.65 25%
Mmcfe $ 8.38 $ 6.42 31%
Operating Revenues (000's):
Oil $ 22,179 $15,603 42%
Natural gas 80,749 78,615 3%
-------- -------
Total Operating Revenues $102,928 $94,218 9%
======== =======
22
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $0.8 million (9%) to $9.6 million during the first six months of 2006,
compared to $8.8 million in 2005. On a unit basis, lease operating expenses
increased $0.18 per Mcfe to $0.78 per Mcfe for the first six months of 2006 from
$0.60 per Mcfe for the first half of 2005. Oil and gas operating expenses
increased due to significantly higher insurance costs due to a May 1, 2006, rate
increase of approximately 480%.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $0.8
million (19%) to $5.3 million for the first six months of 2006, compared to $4.5
million during the same period in 2005 primarily because of an increase in oil
prices and a higher natural gas tax rate, partially offset by a decrease in oil
and natural gas production. 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
$0.252 per Mcf for natural gas for the first six months of 2006, an increase
from $0.208 per Mcf for the first half of 2005. On an equivalent unit of
production basis, severance and ad valorem taxes increased to $0.44 per Mcfe
from $0.31 per Mcfe for the comparable six-month period. Beginning July 1, 2006,
the revised severance tax rate for natural gas production in Louisiana over the
next twelve months will be $0.373 per Mcf. This will significantly increase the
amount of severance taxes being paid in future periods.
DEPLETION AND DEPRECIATION. Depletion and deprecation expense increased $6.5
million (13%) during the first half of 2006 to $57.2 million, from $50.7 million
for the same period of 2005. This was primarily the result of an increase in the
depletion rate as compared to the 2005 period, partially offset by the decline
in oil and natural gas production. On a unit basis, depletion and depreciation
expense increased by $1.19 per Mcfe, to $4.64 per Mcfe for the six months ended
June 30, 2006, compared to $3.45 per Mcfe for the same period in 2005.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was $9.5
million for the first six months of 2006 and for the same period in 2005 was
$9.4 million. On an equivalent unit of production basis, general and
administrative expenses increased $0.13 per Mcfe to $0.77 per Mcfe for the fist
six months of 2006 compared to $0.64 per Mcfe for the comparable 2005 period.
Stock-based compensation expense related to SFAS No. 123R of approximately
$167,000 was recorded in the six months ended June 30, 2006. No stock-based
compensation expense related to SFAS No.123R was recorded in the six-month
period ended June 30, 2005.
HURRICANE DAMAGE REPAIRS. This expense of $2.4 million is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
insurance deductible and costs in excess of insured values.
INTEREST EXPENSE. Interest expense increased $0.8 million (38%), to $2.9 million
for the first six months of 2006 in comparison to the first half of 2005. The
increase is primarily a result of increased interest rates.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the second quarter of 2006, Meridian's capital
expenditures were internally financed with cash from operations. As of June 30,
2006, the Company had a cash balance of $39.3 million and working capital of
$32.1 million.
CASH FLOWS. Net cash provided by operating activities was $75.5 million for the
six months ended June 30, 2006, as compared to $66.8 million for the same period
in 2005. The increase of $8.7 million was primarily due to higher crude oil and
natural gas commodity prices, partially offset by lower production volumes.
23
Net cash used in investing activities was $54.3 million during the six months
ended June 30, 2006, versus $76.3 million in the first six months of 2005. This
decrease was due to lower capital expenditures and proceeds from the sale of
seismic data.
Cash flows used in financing activities during the first six months of 2006 were
$5.1 million, compared to cash used in financing activities of $1.1 million
during the first six months of 2005. This increase in cash used in financing
activities was primarily due to note repayments, partially offset by reduced
preferred stock dividends.
CREDIT FACILITY. On December 23, 2004, the Company amended its 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 was $130 million and it has
been reaffirmed by the syndication group effective April 30, 2006. Repayments of
$10 million were made during the first half of 2006, resulting in an outstanding
balance of $65 million on June 30, 2006.
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. The determination of our borrowing base is subject to a
number of factors, including quantities of proved oil and gas reserves, the
bank's commodity price assumptions and other various factors unique to each
member bank. Our lenders can redetermine the borrowing base to a lower level
than the current borrowing base if they determine that our oil and gas reserves,
at the time of redetermination, are inadequate to support the borrowing base
then in effect.
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 natural 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. As of June 30, 2006, management
believes that the Company is in compliance with all of the covenants of the
Credit Facility.
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
0.5%, 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, 2006, the three-month LIBOR interest rate was
5.48%. 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.
24
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. In 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 may address market risk by
selecting instruments with fluctuating values that correlate strongly with the
underlying commodity being hedged. From time to time we may enter into
derivative contracts to hedge the price risks associated with a portion of
anticipated future oil and gas production. These contracts 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 hedging contracts 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 the six-month period
approximated $65.1 million. Our strategy is to blend exploration drilling
activities with high-confidence workover and development projects in order to
capitalize on periods of high commodity prices. Capital expenditures were for
acreage acquisitions, exploratory drilling, geological and geophysical,
workovers, and related capitalized general and administrative expenses. During
2006, the Company completed operations on ten wells, four of which were placed
on production and six were unproductive wells. In addition, the Company has
drilled two wells in the E. Texas project area through the vertical section of
the well bore and logged apparent Austin Chalk pay. Operations on the wells have
been suspended pending the return of a drilling rig to drill the horizontal
sections of the well bore, and two additional wells are at various stages of
drilling.
The 2006 capital expenditures plan is currently forecast at approximately $132
million. The actual expenditures will be determined based on a variety of
factors, including prevailing prices for oil and natural gas, our expectations
as to future pricing and the level of cash flow from operations. We currently
anticipate funding the 2006 plan utilizing cash flow from operations. When
appropriate, excess cash flow from operations beyond that needed for the 2006
capital expenditures plan will be used to develop additional exploration
prospects or direct payment of debt.
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 Company's 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 were payable semi-annually.
A semi-annual cash dividend of $1.3 million was paid in January 2005.
In 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.
25
FORWARD-LOOKING INFORMATION
From time to time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involve risk and uncertainty. These forward-looking statements may
include, but are not limited to exploration and seismic acquisition plans,
anticipated results from current and future exploration prospects, future
capital expenditure plans and plans to sell properties, anticipated results from
third party disputes and litigation, expectations regarding future financing and
compliance with our credit facility, the anticipated results of wells based on
logging data and production tests, future sales of production, earnings,
margins, production levels and costs, market trends in the oil and natural gas
industry and the exploration and development sector thereof, environmental and
other expenditures and various business trends. Forward-looking statements may
be made by management orally or in writing including, but not limited to, the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section and other sections of our filings with the Securities and
Exchange Commission under the Securities Act of 1933, as amended, and the
Securities Exchange Act of 1934, as amended.
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following:
CHANGES IN THE PRICE OF OIL AND NATURAL GAS. The prices we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that we do not control, including
seasonality, worldwide economic conditions, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other oil-producing countries, the actions of the Organization of
Petroleum Exporting Countries and domestic government regulation, legislation
and policies. Material declines in the prices received for oil and natural gas
could make the actual results differ from those reflected in our forward-looking
statements.
OPERATING RISKS. The occurrence of a significant event against which we are not
fully insured could have a material adverse effect on our financial position and
results of operations. Our operations are subject to all of the risks normally
incident to the exploration for and the production of oil and natural gas,
including uncontrollable flows of oil, natural gas, brine or well fluids into
the environment (including groundwater and shoreline contamination), blowouts,
cratering, mechanical difficulties, fires, explosions, unusual or unexpected
formation pressures, pollution and environmental hazards, each of which could
result in damage to or destruction of oil and natural gas wells, production
facilities or other property, or injury to persons. In addition, we are subject
to other operating and production risks such as title problems, weather
conditions, compliance with government permitting requirements, shortages of or
delays in obtaining equipment, reductions in product prices, limitations in the
market for products, litigation and disputes in the ordinary course of business.
Although we maintain insurance coverage considered to be customary in the
industry, we are not fully insured against certain of these risks either because
such insurance is not available or because of high premium costs. We cannot
predict if or when any such risks could affect our operations. The occurrence of
a significant event for which we are not adequately insured could cause our
actual results to differ from those reflected in our forward-looking statements.
DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit
a prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analysis, production data and engineering
studies, which are inherently imprecise. Therefore, we cannot assure you that
all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause
the actual results to differ from those reflected in our forward-looking
statements.
26
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of available
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.
FULL-COST CEILING TEST. At the end of each quarter, the unamortized cost of oil
and natural gas properties, after deducting the asset retirement obligation, net
of related deferred income taxes, is limited to the sum of the estimated future
net revenues from proved properties using period-end prices, after giving effect
to cash flow hedge positions, discounted at 10%, and the lower of cost or fair
value of unproved properties adjusted for related income tax effects.
The calculation of the ceiling test and the provision for depletion and
amortization are based on estimates of proved reserves. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production, timing, and plan of development. The
accuracy of any reserves estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify a revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and natural gas that are ultimately
recovered.
Due to the imprecision in estimating oil and natural gas revenues as well as the
potential volatility in oil and natural gas prices and their effect on the
carrying value of our proved oil and natural gas reserves, there can be no
assurance that write-downs in the future will not be required as a result of
factors that may negatively affect the present value of proved oil and natural
gas reserves and the carrying value of oil and natural gas properties, including
volatile oil and natural gas prices, downward revisions in estimated proved oil
and natural gas reserve quantities and unsuccessful drilling activities. At June
30, 2006, we had a cushion (i.e. the excess of the ceiling over our capitalized
costs) of $4.0 million (before tax).
BORROWING BASE FOR THE CREDIT FACILITY. The Credit Facility, with Fortis Capital
Corp. as administrative agent, is presently scheduled for borrowing base
redetermination dates on a semi-annual basis with the next such redetermination
scheduled for October 31, 2006. 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.
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
27
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 $65 million remains borrowed under the
Credit Facility, we estimate our annual interest expense will change by $0.65
million for each 100 basis point change in the applicable interest rates
utilized under the Credit Facility.
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 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.
The Company has entered into certain derivative contracts 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. As of June 30, 2006, the
positions hedged approximately 34% of the estimated proved developed natural gas
production and 19% of the estimated proved developed oil production during the
respective terms of the contracts. 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.
Estimated
Fair Value
Asset (Liability)
Notional Floor Price Ceiling Price June 30, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------- -----------------
NATURAL GAS (MMBTU)
Jul 2006 - Oct 2006 Collar 600,000 $ 8.00 $14.50 $ 1,141
Jul 2006 - May 2007 Collar 4,400,000 $ 8.00 $10.60 2,220
-------
Total Natural Gas 3,361
-------
CRUDE OIL (BBLS)
July 2006 Collar 14,000 $37.50 $47.50 (373)
July 2006 Collar 4,000 $40.00 $50.00 (96)
Aug 2006 - Jul 2007 Collar 168,000 $50.00 $74.00 (1,096)
Aug 2007 - Apr 2008 Collar 54,000 $60.00 $82.00 (177)
May 2008 - Jul 2008 Collar 15,000 $60.00 $82.00 (40)
-------
Total Crude Oil (1,782)
-------
$ 1,579
=======
The above excludes hedges entered into after June 30, 2006; see Note 12,
Subsequent Event, for additional information.
28
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE 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 2006.
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 2006 that could
significantly affect these controls.
CHANGES IN INTERNAL CONTROLS
During the three month period ended June 30, 2006, there were no changes in the
Company's internal control over financial reporting that have materially
affected or are reasonably likely to materially affect such internal control
over financial reporting.
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, 2006.
TITLE/LEASE DISPUTES. Title and lease disputes may arise due to various events
that have occurred in the various states in which the Company operates. These
disputes are usually small and could lead to the Company over- or under-stating
our reserves when a final resolution to the title dispute is made.
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, in certain instances, has
indemnified third parties from the claims made in these lawsuits. The Company
has not provided any amount for these matters in its financial statements at
June 30, 2006.
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 1A. RISK FACTORS.
For a discussion of the Company's risk factors, see Item 1A, "Risk Factors", in
the Company's Form 10-K for the year ended December 31, 2005. There have been no
changes to these risk factors during the quarter ended June 30, 2006.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the annual meeting of shareholders held on June 21, 2006, the Company's
shareholders elected two Class I Directors. The following summarizes the votes
for and withheld for each nominee.
Nominee For Withheld
--------------- ---------- ---------
David W. Tauber 68,387,103 9,737,652
John B. Simmons 71,368,410 6,756,345
The terms of the Class II directors (E. L. Henry, Joe E. Kares and Gary A.
Messersmith), and the Class III Directors (Joseph A. Reeves, Jr., Michael J.
Mayell and Fenner R. Weller, Jr.) continued after the meeting.
30
Shareholders also voted to accept a proposal to adopt the Non-Employee Directors
Incentive Plan. The following summarizes the votes related to this proposal.
Broker
Proposal For Against Withheld Non-Vote
---------------------- ---------- --------- -------- ----------
Non-Employee Directors 30,981,907 5,356,350 386,579 41,419,919
Incentive Plan
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 8, 2006 By: /s/ LLOYD V. DELANO
------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
32
EXHIBIT INDEX
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.