UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended: September 30, 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 November 3, 2006: 89,139,600
Page 1 of 44
THE MERIDIAN RESOURCE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
INDEX
Page
Number
------
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Operations (unaudited) for the
Three Months and Nine Months Ended September 30, 2006 and 2005 3
Consolidated Balance Sheets as of September 30, 2006 (unaudited)
and December 31, 2005 4
Consolidated Statements of Cash Flows (unaudited) for the
Nine Months Ended September 30, 2006 and 2005 6
Consolidated Statements of Stockholders' Equity (unaudited) for
the Nine Months Ended September 30, 2006 and 2005 7
Consolidated Statements of Comprehensive Income (Loss)
(unaudited) for the Three Months and Nine Months Ended
September 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 28
Item 4. Controls and Procedures 29
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 29
Item 1a. Risk Factors 30
Item 6. Exhibits 30
SIGNATURES 31
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share information)
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------- --------------------
2006 2005 2006 2005
--------- --------- --------- --------
REVENUES:
Oil and natural gas $ 45,795 $ 36,664 $ 148,723 $130,882
Price risk management activities (238) 60 125 (400)
Interest and other 502 121 1,257 510
--------- --------- --------- --------
46,059 36,845 150,105 130,992
--------- --------- --------- --------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 6,486 3,431 16,050 12,223
Severance and ad valorem taxes 3,202 2,189 8,547 6,687
Depletion and depreciation 28,226 19,725 85,396 70,452
General and administrative 4,360 3,961 13,876 13,345
Accretion expense 430 272 1,050 798
Impairment of long-lived assets 134,865 -- 134,865 --
Hurricane damage repairs 581 750 2,984 750
--------- --------- --------- --------
178,150 30,328 262,768 104,255
--------- --------- --------- --------
EARNINGS (LOSS) BEFORE INTEREST AND INCOME TAXES (132,091) 6,517 (112,663) 26,737
--------- --------- --------- --------
OTHER EXPENSES:
Interest expense 1,471 1,194 4,338 3,276
--------- --------- --------- --------
EARNINGS (LOSS) BEFORE INCOME TAXES (133,562) 5,323 (117,001) 23,461
--------- --------- --------- --------
INCOME TAXES:
Current 135 (860) 503 (603)
Deferred (46,818) 2,907 (40,799) 9,633
--------- --------- --------- --------
(46,683) 2,047 (40,296) 9,030
--------- --------- --------- --------
NET EARNINGS (LOSS) (86,879) 3,276 (76,705) 14,431
Dividends on preferred stock -- -- -- 902
--------- --------- --------- --------
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCKHOLDERS $ (86,879) $ 3,276 $ (76,705) $ 13,529
========= ========= ========= ========
NET EARNINGS (LOSS) PER SHARE:
Basic $ (0.99) $ 0.04 $ (0.88) $ 0.16
Diluted $ (0.99) $ 0.04 $ (0.88) $ 0.15
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 87,726 86,683 87,179 83,771
Diluted 87,726 92,134 87,179 89,337
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
2006 2005
------------- ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 44,917 $ 23,265
Restricted cash 1,265 1,234
Accounts receivable, less allowance for doubtful
accounts of $232 [2006] and $242 [2005] 23,055 41,188
Prepaid expenses and other 6,427 1,294
Assets from price risk management activities 6,522 528
Deferred tax asset -- 1,150
---------- ----------
Total current assets 82,186 68,659
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$61,836 [2006] and $26,623 [2005] not subject to depletion) 1,619,368 1,512,036
Land 48 48
Equipment 7,135 6,540
---------- ----------
1,626,551 1,518,624
Less accumulated depletion and depreciation 1,252,851 1,032,595
---------- ----------
Total property and equipment, net 373,700 486,029
---------- ----------
OTHER ASSETS:
Assets from price risk management activities 634 235
Other 547 879
---------- ----------
Total other assets 1,181 1,114
---------- ----------
TOTAL ASSETS $ 457,067 $ 555,802
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
2006 2005
------------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 7,479 $ 7,595
Revenues and royalties payable 7,923 9,149
Due to affiliates 1,248 4,638
Notes payable 5,187 1,103
Accrued liabilities 21,720 22,272
Liabilities from price risk management activities 1,080 3,977
Asset retirement obligations 3,639 2,879
Deferred income taxes 1,904 --
Current income taxes payable -- 108
--------- ---------
Total current liabilities 50,180 51,721
--------- ---------
LONG-TERM DEBT 75,000 75,000
--------- ---------
OTHER:
Deferred income taxes 1,374 41,967
Liabilities from price risk management activities 302 464
Asset retirement obligations 13,705 9,085
--------- ---------
15,381 51,516
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 6)
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
89,104,503 [2006] and 86,817,658 [2005] shares issued) 927 900
Additional paid-in capital 534,326 524,692
Accumulated deficit (222,100) (145,395)
Accumulated other comprehensive income (loss) 3,754 (2,314)
Unamortized deferred compensation (401) (318)
--------- ---------
Total stockholders' equity 316,506 377,565
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 457,067 $ 555,802
========= =========
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
2006 2005
-------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $(76,705) $ 14,431
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities:
Depletion and depreciation 85,396 70,452
Amortization of other assets 332 333
Non-cash compensation 1,784 1,460
Non-cash price risk management activities (125) 400
Accretion expense 1,050 798
Impairment of long-lived assets 134,865 --
Deferred income taxes (40,799) 9,633
Changes in assets and liabilities:
Restricted cash (31) (1,096)
Accounts receivable 18,133 11,102
Prepaid expenses and other (5,133) (1,412)
Due to affiliates (3,390) (1,713)
Accounts payable (116) (1,650)
Revenues and royalties payable (1,226) (2,373)
Other assets and liabilities 134 (3,933)
-------- ---------
Net cash provided by operating activities 114,169 96,432
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (94,413) (103,837)
Acquisition of properties (13,220) --
Proceeds from (settlements on) sale of property 11,032 (45)
-------- ---------
Net cash used in investing activities (96,601) (103,882)
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt (10,000) --
Proceeds from long-term debt 10,000 --
Reduction in notes payable (5,164) (1,963)
Proceeds from notes payable 9,248 3,142
Issuance of stock/exercise of stock options, net -- 13
Preferred dividends -- (2,166)
Additions to deferred loan costs -- (99)
-------- ---------
Net cash provided by (used in) financing activities 4,084 (1,073)
-------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 21,652 (8,523)
Cash and cash equivalents at beginning of period 23,265 24,297
-------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 44,917 $ 15,774
======== =========
INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ -- $ (30,625)
Issuance of shares for settlement of accrued liabilities $ (794) $ (1,716)
Issuance of shares for acquisition of properties $ (7,000) $ --
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
NINE MONTHS ENDED SEPTEMBER 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 -- 3 1,365 -- -- (1,368) --
Company's 401(k) plan contribution 36 -- 180 -- -- -- 180
Exercise of stock options 49 -- 163 -- -- -- 163
Compensation expense -- -- -- -- -- 1,280 1,280
Accum. other comprehensive loss -- -- -- -- (11,732) -- (11,732)
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 349 4 1,712 -- -- -- 1,716
Preferred dividends -- -- -- (902) -- -- (902)
Net earnings -- -- -- 14,431 -- -- 14,431
------ ---- -------- --------- -------- ------- --------
Balance, September 30, 2005 86,748 $899 $524,175 $(159,715) $(13,306) $ (401) $351,652
====== ==== ======== ========= ======== ======= ========
Balance, December 31, 2005 86,818 $900 $524,692 $(145,395) $ (2,314) $ (318) $377,565
Issuance of rights to common stock -- 4 1,349 -- -- (1,353) --
Company's 401(k) plan contribution 57 1 227 -- -- -- 228
Stock-based compensation-FAS123R -- -- 286 -- -- -- 286
Compensation expense -- -- -- -- -- 1,270 1,270
Accum. other comprehensive income -- -- -- -- 6,068 -- 6,068
Issuance of shares as compensation 224 2 792 -- -- -- 794
Issuance of shares-Vintage acq. 2,006 20 6,980 -- -- -- 7,000
Net loss -- -- -- (76,705) -- -- (76,705)
------ ---- -------- --------- -------- ------- --------
Balance, September 30, 2006 89,105 $927 $534,326 $(222,100) $ 3,754 $ (401) $316,506
====== ==== ======== ========= ======== ======= ========
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 Nine Months Ended
September 30, September 30,
------------------- -------------------
2006 2005 2006 2005
-------- -------- -------- --------
Net earnings (loss) applicable to common stockholders $(86,879) $ 3,276 $(76,705) $ 13,529
Other comprehensive income (loss), net of tax, for unrealized
losses from hedging activities:
Unrealized holding gains (losses) arising during period (1) 4,389 (14,076) 6,994 (20,481)
Reclassification adjustments on settlement of contracts (2) (1,672) 4,314 (926) 8,749
-------- -------- -------- --------
2,717 (9,762) 6,068 (11,732)
-------- -------- -------- --------
Total comprehensive income (loss) $(84,162) $ (6,486) $(70,637) $ 1,797
======== ======== ======== ========
(1) net of income tax benefit (expense) $ (2,363) $ 7,579 $ (3,766) $ 11,028
(2) net of income tax benefit (expense) $ 900 $ (2,323) $ 499 $ (4,711)
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" or "Meridian") 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 ("SEC").
The financial statements included herein as of September 30, 2006, and for the
three and nine month periods ended September 30, 2006 and 2005, are unaudited,
and in the opinion of management, the information furnished reflects all
material adjustments, consisting of normal recurring adjustments, except for the
adjustment for impairment of the Company's oil and natural gas properties as
discussed below, 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. IMPAIRMENT OF LONG-LIVED ASSETS
At the end of each quarter, the unamortized cost of oil and natural gas
properties, 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 qualifying cash flow hedge positions, discounted at 10%,
and the lower of cost or fair value of unproved properties adjusted for related
income tax effects.
Accordingly, based on September 30, 2006, pricing of $4.17 per mcfe of natural
gas and $63.37 per barrel of oil, the Company recognized a non-cash impairment
of $134.9 million ($87.7 million after tax) of the Company's oil and natural gas
properties under the full cost method of accounting.
Due to the substantial volatility in oil and natural gas prices and their effect
on the carrying value of the Company's proved oil and natural gas reserves,
there can be no assurance that future write-downs 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.
3. ACCRUED LIABILITIES
Below is the detail of accrued liabilities on the Company's balance sheets as of
September 30, 2006 and December 31, 2005 (thousands of dollars):
SEPTEMBER 30, DECEMBER 31,
2006 2005
------------- ------------
Capital expenditures $13,620 $12,853
Operating expenses/taxes 4,046 2,794
Hurricane damage repairs -- 2,717
Compensation 1,866 1,949
Interest 486 503
Other 1,702 1,456
------- -------
TOTAL $21,720 $22,272
======= =======
9
4. 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.
As of September 30, 2006, and as of December 31, 2005, the borrowing base under
the Credit Facility was $130 million. The borrowing base under the Credit
Facility was redetermined by the syndication group to be $120 million effective
October 31, 2006. Repayments of $10 million were made during the second quarter
of 2006 and a subsequent borrowing of $10 million was made during the third
quarter of 2006 resulting in an outstanding balance of $75 million on September
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 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 September 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 September 30, 2006, the three-month LIBOR interest
rate was 5.37%. 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.
5. 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.
10
6. 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 September 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 until 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
September 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 CLAIMS. Preliminary discussions with the Company's insurance provider
indicate that there is uncertainty regarding full reimbursement of approximately
$1.0 million of hurricane related costs. This $1.0 million is included on the
Company's balance sheet in accounts receivable. The Company believes that the
$1.0 million claimed for debris removal and other items should be reimbursed and
continues to pursue that result and no reserve is considered necessary.
7. COMMON STOCK
On August 31, 2006, the Company issued 2,005,731 shares of common stock at a
value of $7,000,000 as a portion of the funding for an approximate $20 million
acquisition of properties from Vintage Petroleum LLC. The shares of common stock
issued were based on the closing price of Meridian's common stock for the five
trading days ending on August 4, 2006, or $3.49 per share. The shares issued in
connection with the acquisition are unregistered and bear a legend stating that
they are "restricted shares" as defined by Rule 144 of The Securities Act of
1933. Meridian has agreed to grant registration rights to Vintage Petroleum LLC
which include customary demand and piggy back registration rights for the shares
of Meridian's common stock.
11
8. 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 SEPTEMBER 30,
-------------------
2006 2005
-------- -------
Numerator:
Net earnings (loss) applicable to common stockholders $(86,879) $ 3,276
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 87,726 86,683
Effect of potentially dilutive common shares:
Warrants N/A 4,820
Employee and director stock options N/A 631
-------- -------
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions 87,726 92,134
======== =======
Basic earnings (loss) per share $ (0.99) $ 0.04
======== =======
Diluted earnings (loss) per share $ (0.99) $ 0.04
======== =======
NINE MONTHS
ENDED SEPTEMBER 30,
-------------------
2006 2005
-------- -------
Numerator:
Net earnings (loss) applicable to common stockholders $(76,705) $13,529
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 87,179 83,771
Effect of potentially dilutive common shares:
Warrants N/A 4,701
Employee and director stock options N/A 865
-------- -------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 87,179 89,337
======== =======
Basic earnings (loss) per share $ (0.88) $ 0.16
======== =======
Diluted earnings (loss) per share $ (0.88) $ 0.15
======== =======
9. 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, the Company 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 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
12
minimal on these transactions. In the event of nonperformance, the Company would
be exposed to price risk. The Company has some risk of accounting loss since the
price received for the product at the actual physical delivery point may differ
from the prevailing price at the delivery point required for settlement of the
hedging transaction.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various
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 $(0.2) million and $0.1 million during the three months ended
September 30, 2006, and September 30, 2005, respectively, and $0.1 million and
$(0.4) million during the nine months ended September 30, 2006, and September
30, 2005, respectively.
At September 30, 2006, the Company's oil and natural gas derivatives had an
unrealized gain of $5.8 million ($3.8 million net of tax) which is recorded in
accumulated other comprehensive income (loss) on the Company's consolidated
balance sheet. Based upon September 30, 2006 oil and natural gas commodity
prices, approximately $5.4 million of the gain deferred in accumulated other
comprehensive income could potentially increase gross revenues over the next
twelve months. As of September 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 $2,572,000 and ($5,517,000) for the three months ended September 30,
2006 and 2005, respectively, and by $1,425,000 and ($12,340,000) for the nine
months ended September 30, 2006 and 2005, respectively, as a result of hedging
transactions.
The Notional Amount in the table below is equal to the total net volumetric
hedge position of the Company during the periods presented. As of September 30,
2006, the positions hedged approximately 31% of the estimated proved developed
natural gas production and 26% of the estimated proved developed oil production
during the respective terms of the hedging agreements. The fair values of the
hedges are based on the difference between the strike price and the New York
Mercantile Exchange future prices for the applicable trading months.
The fair value of the Company's hedging agreements is recorded on the
consolidated balance sheet as separately identified assets or liabilities. The
estimated fair value of the hedging agreements as of September 30, 2006, is
provided below:
13
Estimated
Fair Value
Asset (Liability)
Notional Floor Price Ceiling Price September 30, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------- ------------------
NATURAL GAS (MMBTU)
Oct 2006 Collar 140,000 $ 8.00 $14.50 $ 532
Oct 2006 - May 2007 Collar 3,200,000 $ 8.00 $10.60 5,001
------
Total Natural Gas 5,533
------
CRUDE OIL (BBLS)
Oct 2006 - July 2007 Collar 135,000 $50.00 $74.00 (234)
Aug 2007 - April 2008 Collar 54,000 $60.00 $82.00 8
May 2008 - July 2008 Collar 15,000 $60.00 $82.00 2
Oct 2006 - July 2007 Collar 39,000 $60.00 $96.10 60
Aug 2007 - July 2008 Collar 52,000 $65.00 $93.15 189
Aug 2007 - July 2008 Collar 40,000 $70.00 $87.40 216
------
Total Crude Oil 241
------
$5,774
======
10. 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 entitled "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 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
$119,000 and $286,000 was recorded in the three months and nine months ended
September 30, 2006, respectively. No stock-based compensation expense related to
SFAS No. 123R was recorded in the three or nine month periods ended September
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 Nine Months
Ended Ended
September 30, September 30,
2005 2005
------------- -------------
Net earnings applicable to common stockholders as reported $3,276 $13,529
Stock-based compensation expense determined under fair
value method for all awards, net of tax (64) (162)
------ -------
Pro forma earnings applicable to common stockholders $3,212 $13,367
====== =======
Basic earnings per share:
As reported $ 0.04 $ 0.16
Pro forma $ 0.04 $ 0.16
Diluted earnings per share:
As reported $ 0.04 $ 0.15
Pro forma $ 0.04 $ 0.15
11. 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
dismantlement and abandonment costs of oil and natural gas properties, excluding
salvage values.
The following table describes the change in the Company's asset retirement
obligations for the nine months ended September 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 4,437
Settlements during 2006 (191)
Revisions to estimates during 2006 84
Accretion expense for 2006 1,050
-------
Asset retirement obligation at September 30, 2006 $17,344
=======
15
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 obligations
to plug the natural gas and oil wells and costs to do so.
12. 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.
13. 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.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 ("SAB 108").
Due to diversity in practice among registrants, SAB 108 expresses SEC staff
views regarding the process by which misstatements in financial statements are
evaluated for purposes of determining whether financial statement restatement is
necessary. SAB 108 is effective for fiscal years ending after November 15, 2006,
and early application is encouraged. The Company does not expect SAB 108 to have
a material impact on our financial position or results of operations.
In September 2006, the FASB issued SFAS No. 157 ("SFAS 157"), "Fair Value
Measurements". SFAS 157 defines fair value, establishes a framework for
measuring fair value in generally accepted accounting principles and expands
disclosure about fair value measurements. SFAS 157 is effective for financial
statements issued for fiscal years beginning after November 15, 2007. The
Company is evaluating the impact, if any, that SFAS 157 will have on our
financial statements.
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL.
EAST TEXAS
The Company recently announced initial production test results on its Blackstone
Minerals ("BSM") No. 1 well, located in Polk County, Texas in the Company's East
Texas Austin Chalk/Woodbine Play. The well was recently tested over a two day
period at gross daily flow rates as high as 27 million cubic feet of natural gas
per day ("Mmcf/d") and as high as 1,500 barrels of oil per day ("BOPD"). Flowing
tubing pressures were measured at ranges between 7,500 pounds per square inch
("psi") through an 18/64th-inch choke and 2,400 psi through a 48/64th-inch
choke. The dual lateral well was placed on production and is in a "clean-up" of
drilling fluids phase with intermittent fluctuations normally experienced during
the first several day phases of production for wells similarly drilled and
produced in the area. Pipeline constraints during the clean-up operations
prevent the well from being produced at more than 20 Mmcf/d. The well was placed
on production at a gross rate of approximately 18-20 Mmcf/d along with an
additional 1,000 to 1,500 BOPD. The Company's working interest in the well is
approximately 84% before payout (57% net) and 71% after payout (50% net),
subject to terms of unitization, lease royalties, acreage and farmout agreements
previously negotiated with the third party working and mineral interest owners
in the well.
The well was drilled vertically to approximately 13,000 feet with two horizontal
laterals and is on trend with other Austin Chalk wells in the area which are
located approximately nine miles to the east. The Company expects that the well
will display similar producing characteristics to other Austin Chalk wells in
the area, with the typical hyperbolic decline curve from current production
levels during the coming months.
The Company anticipates mobilizing two rigs (one rig for a one-well drilling and
the second for an indeterminable time period at the discretion of the Company)
into the area beginning in December 2006 to commence the drilling of additional
laterals in at least two of three of the existing vertical wells that were
drilled through the Austin Chalk during early 2006. The first well scheduled for
the laterals is the Katherine Leary No. 1 well which is located northeast of the
current well, followed by either the BSM No. 2 or No. 3 well.
The Company is also under way with the construction and purchase of two newly
built drilling rigs in conjunction with an engineering design and
fabrication/rig contractor. This contractor will ultimately operate, crew and
maintain the rigs. Delivery of the rigs is currently expected during mid-summer
2007. The rigs will be mobilized to the Company's East Texas Austin Chalk play
and, depending on the successes of the operations and commodity prices, the
Company has plans for a two-rig, multi-well drilling program to exploit the
Company's acreage under lease for an anticipated 3 to 5 year period.
Additionally, the Company has recently executed a lease and Joint Exploration
Agreement with Blackstone Minerals LP et al to acquire approximately 20,300
gross acres (17,500 net), bringing the Company's and its working interest
partners' acreage position to approximately 35,000 gross acres (30,000, net) in
the area. Depending on unit configuration, Meridian estimates that this
represents an additional 25 to 50 potential drilling locations to test the
Austin Chalk and Woodbine formations. Working interest will vary between 25% and
92%.
SOUTH LOUISIANA
The Company has stepped up its drilling and completion activities in its south
Louisiana region with two wells being placed on production during the fourth
quarter 2006 and expectations of 4 to 6 additional wells to be drilled back to
back beginning in the fourth quarter 2006.
17
At the "Y-Not" prospect, the J. A. Smith No. 1 well, located in the Company's
Weeks Island field, Iberia Parish, Louisiana, was recently placed on production
and is flowing into the sales pipeline at a gross rate of 2.5 Mmcf/d and 81
barrels of condensate per day ("BCPD") with no water. The well was drilled to
approximately 16,000 feet and logged approximately 30 feet of overall gross gas
pay in the Lower Miocene sand section. The Company owns an approximate 97%
working interest (74% net revenue interest) in the well, subject to final unit
surveys.
Further, the Company is currently drilling the Lake Arthur Reclamation No. 1
well in Cameron Parish, Louisiana on its North Grand Lake prospect. The well is
scheduled to reach a total depth of approximately 16,000 feet to test the main
Marg sand. The Company has a 55% before casing point (64% after casing point)
working interest in this well, and the gross unrisked reserve target is between
25 and 50 BCF. The first of two casing strings has been set and the well is
currently at a depth of approximately 13,000 feet.
Following the drilling of the North Grand Lake prospect, the Company will
mobilize its barge rig under contract to the first of three additional Hackberry
sand prospects located in Calcasieu Parish, Louisiana.
Additionally, the Company anticipates spudding of the Turtle Soup prospect
located in Acadia Parish, Louisiana during the fourth quarter 2006, which is
designed to test the Marg-Tex sands at an approximate depth of 15,000 feet with
a gross unrisked reserve target of 50 BCFE. The Company will own a non-operating
23% working interest after payout.
The Apache La. Minerals No. 1 well on the Bayou Gentilly prospect, continues to
await the pipeline operator's completion of the hot tap prior to production.
Originally, the well was drilled and tested at approximately 6.5 Mmcfe/d prior
to Hurricane Katrina during August 2005 but has been awaiting the pipeline
company's mobilization of crews and equipment to the site since that date. Due
to circumstances beyond our control, the tie-in date of this project has been
extended monthly and is now scheduled for mid-November. The Company owns a 92%
working interest in this well.
In the Biloxi Marshland area, the natural gas transmission company that takes
gas from three of the four field production facilities will conduct scheduled
maintenance of its pipeline estimated to begin in mid-November 2006. This
maintenance will cause the shut-in of several wells in the Biloxi Marshland
field for an estimated period of up to one month. The amount of production being
shut-in during that time is estimated to be 25 Mmcf/d net. During this period,
Meridian will make improvements to the three facilities as well as assist the
crews performing line maintenance in an effort to expedite the return to
production of our wells in a timely manner.
TEXAS GULF COAST (OFFSHORE)
In similar fashion to the stepped-up drilling in south Louisiana, as a result of
the recent purchase by the Company of the Vintage Petroleum LLC south Texas
offshore properties, the Company anticipates drilling 6 to 8 wells in this
region during the upcoming quarters. Two of the wells have recently been drilled
- -- the Countiss McCracken No. 1 and the BP America No. 1 wells, located in
Nueces Bay, San Patricio and Nueces Counties. Both of these wells were drilled
to a total depth of approximately 13,000 feet and have been placed on production
at gross daily flow rates of approximately 2.2 and 7.1 Mmcfe per day,
respectively, from the lower Frio formation. Meridian has an approximate working
interest of 25% in each well.
Additionally, during the fourth quarter 2006, the Company has entered into a
contract for a rig to drill its ST 786 No. 12 well on its Indian Point prospect,
also located in the Nueces Bay area immediately east of the wells described
above. This well will target lower Frio sands similar to those encountered by
the wells
18
mentioned above and has been designed to be drilled to a total depth of 14,500
feet (MD). Meridian has a 49% working interest in this prospect and is the
operator.
Additional prospects are being readied for drilling beginning in the first
quarter 2007 and include the Company's Brazos 388 / 400 prospect and High Island
55 prospect, each a product of the Vintage purchase. Total gross unrisked
reserve target exposure from drilling all of the prospects and wells acquired
from Vintage ranges between 50 and 150 BCFE.
NORTH CENTRAL OKLAHOMA
During the fourth quarter of 2006, a rig will be moved onto location in the
producing trend of the Hunton/Woodford De-watering Play to drill six initial
wells to test two separate areas of the play--two saltwater disposal wells and
sequentially four exploration/exploitation wells, each to an approximate depth
of 7,500 feet. The Company, which will operate the field, owns approximately
20,000 acres in the area and has targeted gross unrisked reserves for this play
of approximately 30 to 40 Bcfe. Meridian will own a 92% working interest
position.
UNCONVENTIONAL RESOURCE PLAYS
In the Delaware Basin, the Company and its joint venture partner are currently
reprocessing several 2-D seismic lines and plans to acquire approximately 77
miles of additional 2-D seismic during December 2006 over portions of their
75,000 acreage position. Plans are to initiate drilling operations during early
2007. Targeted formations are the Barnett and Woodford Shale sections which
range between 5,500 and 8,500 feet. Meridian's 50% joint venture partner will
operate substantially all of the drilling and production for the project.
In the New Albany Play of the Illinois Basin, the Company continues to acquire
leases and currently owns an approximate 25,000-acre lease position. Targeted
formations are the New Albany Shale at depths generally between 2,000 and 5,000
feet with an expected average thickness of 300 feet. Plans are being made to
initiate drilling activities during late fourth quarter 2006 and continue
through 2007. The Company's working interest in the play is approximately 92%
with Meridian as operator.
In the Palo Duro Basin Play, the Company owns 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 an estimated average
shale thickness of 1,000 feet. Several operators in the basin are in various
stages of testing optimal drilling and completion techniques for wells in the
area. The Company is currently developing its operational plan for the basin
with expectations to initiate drilling during 2007. Meridian is the operator.
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 September 30,
2006, was $64.17 per barrel compared to $43.92 per barrel for the three months
ended September 30, 2005, and $56.01 per barrel for the three months ended June
30, 2006. Our average natural gas price (after adjustments for hedging
activities) for the three months ended September 30, 2006, was $7.16 per Mcf
compared to $7.32 per Mcf for the three months ended September 30, 2005, and
$7.29 per Mcf for the three months ended June 30, 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
19
capital markets, which could impact our revenues, profitability and ability to
maintain or increase our exploration and development program.
IMPAIRMENT OF LONG-LIVED ASSETS. A decline in oil and natural gas prices as of
September 30, 2006, resulted in a non-cash impairment of $134.9 million ($87.7
million after tax) of the Company's oil and natural gas properties under the
full cost method of accounting. See Note 2, Impairment of Long-Lived Assets, for
additional information.
Due to the substantial volatility in oil and natural gas prices and their effect
on the carrying value of the Company's proved oil and natural gas reserves,
there can be no assurance that future write-downs 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.
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 SEPTEMBER 30, 2006 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2005
OPERATING REVENUES. Third quarter 2006 oil and natural gas revenues, which
include oil and natural gas hedging activities (see Note 9 of Notes to
Consolidated Financial Statements), increased $9.1 million (25%) as compared to
third quarter 2005 revenues due to a 10% increase in average commodity prices on
a natural gas equivalent basis, and a 14% increase in production volumes. Oil
and natural gas production volume totaled 5,715 Mmcfe for the third quarter of
2006 compared to 5,010 Mmcfe for the comparable period of 2005. Our average
daily production increased from 54.5 Mmcfe during the third quarter of 2005 to
62.1 Mmcfe for the third quarter of 2006. The increase in average daily
production volumes between the two periods is due in part to hurricane-related
losses in 2005. Additional variance differences can be attributed to new
discoveries brought on between the comparable periods more than offset by
natural production declines.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended September 30, 2006
and 2005:
20
THREE MONTHS
ENDED
SEPTEMBER 30,
----------------- INCREASE
2006 2005 (DECREASE)
------- ------- ----------
Production Volumes:
Oil (Mbbl) 230 203 13%
Natural gas (MMcf) 4,337 3,790 14%
Mmcfe 5,715 5,010 14%
Average Sales Prices:
Oil (per Bbl) $ 64.17 $ 43.92 46%
Natural gas (per Mcf) $ 7.16 $ 7.32 (2%)
Mmcfe $ 8.01 $ 7.32 10%
Operating Revenues (000's):
Oil $14,760 $ 8,916 66%
Natural gas 31,035 27,748 12%
------- -------
Total Operating Revenues $45,795 $36,664 25%
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $3.1 million (89%) to $6.5 million during the third quarter of 2006,
compared to $3.4 million in 2005. On a unit basis, lease operating expenses
increased $0.45 per Mcfe to $1.13 per Mcfe for the third quarter of 2006 from
$0.68 per Mcfe for the third quarter of 2005. Lease operating expense increased
between the periods primarily due to additional properties acquired and drilled
since the last period, industry wide increases in service costs and
significantly higher insurance costs resulting from last year's hurricane
season. The Company's insurance rates increased by more than four times the
previous year's annual premiums and represented $1.5 million during the third
quarter of 2006. The Company anticipates that the higher insurance costs for
properties in its Gulf Coast producing region will continue in effect for the
foreseeable future.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $1.0
million (46%) to $3.2 million for the third quarter of 2006, compared to $2.2
million during the same period in 2005 primarily because of an increase in oil
prices, a higher natural gas tax rate, and an increase 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 $0.373 per Mcf for natural gas, an increase from
$0.252 per Mcf for the third quarter of 2006. On an equivalent unit of
production basis, severance and ad valorem taxes increased to $0.56 per Mcfe
from $0.44 per Mcfe for the comparable three-month period.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $8.5
million (43%) during the third quarter of 2006 to $28.2 million, from $19.7
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 and an increase in
oil and natural gas production. On a unit basis, depletion and depreciation
expense increased by $1.00 per Mcfe, to $4.94 per Mcfe for the three months
ended September 30, 2006, compared to $3.94 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.
As a result of the below-referenced ceiling test write-down, the Company's
future depletion rate is expected to decrease.
IMPAIRMENT OF LONG-LIVED ASSETS. A decline in oil and natural gas prices as of
September 30, 2006, resulted in the Company recognizing a non-cash impairment
totaling $134.9 million ($87.7 million after tax) of its oil and natural gas
properties under the full cost method of accounting. Additionally, the effect of
this
21
write-down is projected to result in a decrease in the Company's anticipated
future depletion rate. See Note 2, Impairment of Long-Lived Assets, for
additional information.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was $4.4
million for 2006 and $4.0 million for 2005. This increase was primarily due to
increased compensation costs and professional service fees, partially offset by
lower accounting costs. On an equivalent unit of production basis, general and
administrative expenses decreased $0.03 per Mcfe to $0.76 per Mcfe for the third
quarter of 2006 compared to $0.79 per Mcfe for the comparable 2005 period
primarily due to increased production rates between the periods. Stock-based
compensation expense related to SFAS No. 123R of approximately $119,000 was
recorded in the three months ended September 30, 2006. No stock-based
compensation related to SFAS No. 123R expense was recorded in the three month
period ended September 30, 2005.
HURRICANE DAMAGE REPAIRS. This expense of $0.6 million is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
repair costs in excess of insured values.
INTEREST EXPENSE. Interest expense increased $0.3 million (23%), to $1.5 million
for the third quarter of 2006 in comparison to the third quarter of 2005. The
increase is primarily a result of increased interest rates.
NINE MONTHS ENDED SEPTEMBER 30, 2006 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2005
OPERATING REVENUES. Oil and natural gas revenues during the nine months ended
September 30, 2006, increased $17.8 million (14%) as compared to revenues during
the same period in 2005 due to a 24% increase in average commodity prices on a
natural gas equivalent basis, partially offset by a 9% 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 that
delayed returning production in the earlier part of 2006 to pre-storm levels.
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 72.2 Mmcfe during the first nine
months of 2005 to 65.9 Mmcfe for the first nine months of 2006. Oil and natural
gas production volume totaled 17,997 Mmcfe for the first nine months of 2006,
compared to 19,706 Mmcfe for the comparable period of 2005.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the nine months ended September 30, 2006
and 2005:
NINE MONTHS ENDED
SEPTEMBER 30,
------------------- INCREASE
2006 2005 (DECREASE)
-------- -------- ----------
Production Volumes:
Oil (Mbbl) 653 680 (4%)
Natural gas (MMcf) 14,081 15,623 (10%)
Mmcfe 17,997 19,706 (9%)
Average Sales Prices:
Oil (per Bbl) $ 56.59 $ 36.03 57%
Natural gas (per Mcf) $ 7.94 $ 6.81 17%
Mmcfe $ 8.26 $ 6.64 24%
Operating Revenues (000's):
Oil $ 36,939 $ 24,519 51%
Natural gas 111,784 106,363 5%
-------- --------
Total Operating Revenues $148,723 $130,882 14%
======== ========
22
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $3.8 million (31%) to $16.0 million during the first nine months of
2006, compared to $12.2 million in 2005. On a unit basis, lease operating
expenses increased $0.27 per Mcfe to $0.89 per Mcfe for the first nine months of
2006 from $0.62 per Mcfe for the comparable period of 2005. Oil and natural gas
operating expenses increased primarily due to additional properties acquired and
wells drilled since last year, industry wide increases in service costs and
significantly higher insurance costs resulting from last year's hurricane
season. The Company's insurance rates increased by more than four times the
previous year's annual premiums and represented $1.7 million of the increase for
the comparable periods. The Company anticipates that the higher insurance costs
will continue in effect for the foreseeable future.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $1.8
million (28%) to $8.5 million for the first nine months of 2006, compared to
$6.7 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
$0.373 per Mcf (effective July 1, 2006) for natural gas. For the first six
months of 2006 and the last six months of 2005, the rate was $0.252 per Mcf for
natural gas, 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
$0.47 per Mcfe in 2006 from $0.34 per Mcfe for the comparable nine-month period
in 2005.
DEPLETION AND DEPRECIATION. Depletion and deprecation expense increased $14.9
million (21%) during the first nine months of 2006 to $85.4 million, from $70.5
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 $1.17 per Mcfe, to $4.75 per Mcfe for the nine
months ended September 30, 2006, compared to $3.58 per Mcfe for the same period
in 2005. As a result of the below-referenced ceiling test write-down, the
Company's future depletion rate is expected to decrease.
IMPAIRMENT OF LONG-LIVED ASSETS. A decline in oil and natural gas prices as of
September 30, 2006, resulted in the Company recognizing a non-cash impairment
totaling $134.9 million ($87.7 million after tax) of its oil and natural gas
properties under the full cost method of accounting. Additionally, the effect of
this write-down is projected to result in a decrease in the Company's
anticipated future depletion rate. See Note 2, Impairment of Long-Lived Assets,
for additional information.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was $13.9
million for the first nine months of 2006 and for the same period in 2005 was
$13.3 million. The increase is primarily due to increased compensation costs,
partially offset by a decrease in professional services. On an equivalent unit
of production basis, general and administrative expenses increased $0.09 per
Mcfe to $0.77 per Mcfe for the first nine months of 2006 compared to $0.68 per
Mcfe for the comparable 2005 period. Stock-based compensation expense related to
SFAS No. 123R of approximately $286,000 was recorded in the nine months ended
September 30, 2006. No stock-based compensation expense related to SFAS No.123R
was recorded in the nine-month period ended September 30, 2005.
HURRICANE DAMAGE REPAIRS. This expense of $3.0 million is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
insurance deductible and repair costs in excess of insured values.
INTEREST EXPENSE. Interest expense increased $1.0 million (32%), to $4.3 million
for the first nine months of 2006 in comparison to the first nine months of
2005. The increase is primarily a result of increased interest rates.
23
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first nine months of 2006, Meridian's capital
expenditures were internally financed with cash from operations. As of September
30, 2006, the Company had a cash balance of $44.9 million and working capital of
$32.0 million.
CASH FLOWS. Net cash provided by operating activities was $114.2 million for the
nine months ended September 30, 2006, as compared to $96.4 million for the same
period in 2005. The increase of $17.8 million was primarily due to higher crude
oil and natural gas commodity prices, partially offset by lower production
volumes.
Net cash used in investing activities was $96.6 million during the nine months
ended September 30, 2006, versus $103.9 million in the first nine months of
2005. This decrease was primarily due to the proceeds received from the sale of
seismic data.
Cash flows provided by financing activities during the first nine months of 2006
were $4.1 million, compared to cash used in financing activities of $1.1 million
during the first nine months of 2005. This increase in cash provided by
financing activities was primarily due to note borrowings related to the
Company's insurance renewal and 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.
As of September 30, 2006, and as of December 31, 2005, the borrowing base under
the Credit Facility was $130 million. The borrowing base under the Credit
Facility was redetermined by the syndication group to be $120 million effective
October 31, 2006. Repayments of $10 million were made during the second quarter
of 2006 and a subsequent borrowing of $10 million was made during the third
quarter of 2006 resulting in an outstanding balance of $75 million on September
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 September 30, 2006,
management believes that the Company is in compliance with all of the covenants
of the Credit Facility.
24
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 September 30, 2006, the three-month LIBOR interest
rate was 5.37%. 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. 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 natural 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 nine month period
approximated $108 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, related capitalized general and administrative expenses and a
marginal amount related to producing properties. During 2006, the Company has
drilled 16 wells, six of which were placed on production, four have been logged
with apparent pay and six were unproductive wells. In addition, the Company has
drilled two wells in the East 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 $153
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.
25
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. A semi-annual
cash dividend of $1.3 million was paid in January 2005 on the Company's 8.5%
Redeemable Convertible Preferred Stock.
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.
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.
26
DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit
a prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analysis, production data and engineering
studies, which are inherently imprecise. Therefore, we cannot assure you that
all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause
the actual results to differ from those reflected in our forward-looking
statements.
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of 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, 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 qualifying 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.
Accordingly, based on September 30, 2006, pricing of $4.17 per mcfe of natural
gas and $63.37 per barrel of oil, the Company recognized a non-cash impairment
of $134.9 million ($87.7 million after tax) of the Company's oil and natural gas
properties under the full cost method of accounting. 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 future write-downs
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.
27
BORROWING BASE FOR THE CREDIT FACILITY. The Credit Facility, with Fortis Capital
Corp. as administrative agent, is subject to semi-annual borrowing base
redeterminations, April 30 and October 31 of each year. 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. 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. As of September 30, 2006, and as of December 31, 2005, the
borrowing base under the Credit Facility was $130 million. The borrowing base
under the Credit Facility was redetermined by the syndication group to be $120
million effective October 31, 2006.
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 million remains borrowed under the Credit Facility, 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
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 September 30, 2006,
the positions hedged approximately 31% of the estimated proved developed natural
gas production and 26% 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.
28
Estimated
Fair Value
Asset (Liability)
Notional Floor Price Ceiling Price September 30, 2006
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------- ------------------
NATURAL GAS (MMBTU)
Oct 2006 Collar 140,000 $ 8.00 $14.50 $ 532
Oct 2006 - May 2007 Collar 3,200,000 $ 8.00 $10.60 5,001
------
Total Natural Gas 5,533
------
CRUDE OIL (BBLS)
Oct 2006 - July 2007 Collar 135,000 $50.00 $74.00 (234)
Aug 2007 - April 2008 Collar 54,000 $60.00 $82.00 8
May 2008 - July 2008 Collar 15,000 $60.00 $82.00 2
Oct 2006 - July 2007 Collar 39,000 $60.00 $96.10 60
Aug 2007 - July 2008 Collar 52,000 $65.00 $93.15 189
Aug 2007 - July 2008 Collar 40,000 $70.00 $87.40 216
------
Total Crude Oil 241
------
$5,774
======
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 third 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 third quarter of 2006 that could
significantly affect these controls.
CHANGES IN INTERNAL CONTROLS
During the three month period ended September 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.
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
29
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 September 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
September 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 September 30, 2006.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
On August 31, 2006, the Company issued 2,005,731 shares of common stock at a
value of $7,000,000 as a portion of the funding for an approximate $20 million
acquisition of properties from Vintage Petroleum LLC. The shares issued in
connection with the acquisition were not registered under the Securities Act of
1933, as amended, in reliance on Section 4(2) of that Act as a transaction by an
issuer not involving any public offering. See Note 7 of the Notes to
Consolidated Financial Statements.
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.
30
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
(Registrant)
Date: November 9, 2006 By: /s/ LLOYD V. DELANO
-------------------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
31
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.