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, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission file number: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-597-7000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 and 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
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 4, 2005: 86,765,263
Page 1 of 38
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, 2005 and 2004 3
Consolidated Balance Sheets as of September 30, 2005 (unaudited)
and December 31, 2004 4
Consolidated Statements of Cash Flows (unaudited) for the
Nine Months Ended September 30, 2005 and 2004 6
Consolidated Statements of Stockholders' Equity (unaudited) for the
Nine Months Ended September 30, 2005 and 2004 7
Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the
Three Months and Nine Months Ended September 30, 2005 and 2004 8
Notes to Consolidated Financial Statements (unaudited) 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk 29
Item 4. Controls and Procedures 30
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 31
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, except per share information)
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- ----------------------
2005 2004 2005 2004
--------- --------- --------- ---------
REVENUES:
Oil and natural gas $ 36,664 $ 52,951 $ 130,882 $ 149,156
Price risk management activities 60 ---- (400) ----
Interest and other 121 86 510 176
--------- --------- --------- ---------
36,845 53,037 130,992 149,332
--------- --------- --------- ---------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 3,431 3,057 12,223 8,811
Severance and ad valorem taxes 2,189 2,176 6,687 7,005
Depletion and depreciation 19,725 28,387 70,452 77,440
General and administrative 3,961 4,028 13,345 10,723
Hurricane damage repairs 750 ---- 750 ----
Write-down of securities held ---- 195 ---- 195
Accretion expense 272 147 798 414
--------- --------- --------- ---------
30,328 37,990 104,255 104,588
--------- --------- --------- ---------
EARNINGS BEFORE INTEREST AND INCOME TAXES 6,517 15,047 26,737 44,744
--------- --------- --------- ---------
OTHER EXPENSES:
Interest expense 1,194 1,624 3,276 5,594
Debt conversion expense ---- ---- ---- 1,188
--------- --------- --------- ---------
1,194 1,624 3,276 6,782
--------- --------- --------- ---------
EARNINGS BEFORE INCOME TAXES 5,323 13,423 23,461 37,962
--------- --------- --------- ---------
INCOME TAXES:
Current (860) (600) (603) 1,500
Deferred 2,907 5,500 9,633 12,500
--------- --------- --------- ---------
2,047 4,900 9,030 14,000
--------- --------- --------- ---------
NET EARNINGS: 3,276 8,523 14,431 23,962
Dividends on preferred stock ---- 737 902 3,144
--------- --------- --------- ---------
NET EARNINGS APPLICABLE
TO COMMON STOCKHOLDERS $ 3,276 $ 7,786 $ 13,529 $ 20,818
========= ========= ========= =========
NET EARNINGS PER SHARE:
Basic $ 0.04 $ 0.10 $ 0.16 $ 0.30
Diluted $ 0.04 $ 0.09 $ 0.15 $ 0.27
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 86,683 76,678 83,771 69,690
Diluted 92,134 83,359 89,337 76,852
See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
2005 2004
------------- ------------
(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 15,774 $ 24,297
Restricted cash 1,987 891
Accounts receivable, less allowance for doubtful accounts of
$240 [2005 and 2004] 16,661 27,763
Prepaid expenses and other 3,675 2,263
Assets from price risk management activities 440 5,705
---------- ----------
Total current assets 38,537 60,919
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $36,596 [2005] and $34,731 [2004]
not subject to depletion) 1,482,169 1,377,649
Land 48 478
Equipment and other 6,476 10,039
---------- ----------
1,488,693 1,388,166
Less accumulated depletion and depreciation 1,005,693 938,965
---------- ----------
Total property and equipment, net 483,000 449,201
---------- ----------
OTHER ASSETS 1,443 2,272
---------- ----------
TOTAL ASSETS $ 522,980 $ 512,392
========== ==========
See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
SEPTEMBER 30, DECEMBER 31,
2005 2004
------------- ---------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 13,333 $ 14,983
Revenues and royalties payable 5,744 8,117
Due to affiliates 2,153 3,866
Notes payable 2,049 870
Accrued liabilities 15,670 21,406
Liabilities from price risk management activities 19,650 8,003
Asset retirement obligations 3,065 1,331
Current income taxes payable ---- 105
--------- ---------
Total current liabilities 61,664 58,681
--------- ---------
LONG-TERM DEBT 75,129 75,129
--------- ---------
OTHER:
Deferred income taxes 25,958 22,639
Liabilities from price risk management activities 864 -----
Asset retirement obligations 7,709 8,293
Other 4 20
--------- ---------
34,535 30,952
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 5)
REDEEMABLE CONVERTIBLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized, None [2005] and
315,886 [2004] shares of Series C Redeemable
Convertible Preferred Stock outstanding at stated value) ---- 31,589
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
86,748,469 [2005] and 79,215,394 [2004] outstanding) 899 821
Additional paid-in capital 524,175 490,351
Accumulated deficit (159,715) (173,244)
Accumulated other comprehensive loss (13,306) (1,574)
Unamortized deferred compensation (401) (313)
--------- ---------
Total stockholders' equity 351,652 316,041
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 522,980 $ 512,392
========= =========
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,
------------------------
2005 2004
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 14,431 $ 23,962
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Debt conversion expense ---- 1,188
Depletion and depreciation 70,452 77,440
Amortization of other assets 333 1,468
Non-cash compensation 1,460 1,267
Non-cash price risk management activities 400 ----
Write-down of securities held ---- 195
Accretion expense 798 414
Deferred income taxes 9,633 12,500
Changes in assets and liabilities:
Restricted cash (1,096) ----
Accounts receivable 11,102 (362)
Prepaid expenses and other (1,412) (1,528)
Due to affiliates (1,713) 1,614
Accounts payable (1,650) 1,904
Revenues and royalties payable (2,373) (3,935)
Accrued liabilities and other (3,933) 10,934
--------- ---------
Net cash provided by operating activities 96,432 127,061
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (103,837) (99,899)
Proceeds from (settlements on) sale of property (45) (73)
--------- ---------
Net cash used in investing activities (103,882) (99,972)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt ---- (53,320)
Increase in notes payable, net 1,179 1,404
Issuance of stock/exercise of options, net 13 95,009
Repurchase of common stock ---- (49,291)
Preferred dividends (2,166) (5,248)
Additions to deferred loan costs (99) (16)
--------- ---------
Net cash used in financing activities (1,073) (11,462)
--------- ---------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (8,523) 15,627
--------- ---------
Cash and cash equivalents at beginning of period 24,297 12,821
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 15,774 $ 28,448
--------- ---------
INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ (30,625) $ (27,766)
Issuance of shares for settlement of accrued liabilities $ (1,716) $ ----
Conversion of convertible subordinated debt $ ---- $ (20,000)
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
NINE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004
(in thousands)
(unaudited)
Common Stock Additional
------------------------ Paid-In Accumulated
Shares Par Value Capital Deficit
--------- --------- --------- ---------
Balance, December 31, 2003 61,725 $ 644 $ 394,177 $(202,492)
Issuance of rights to common stock ----- 3 1,388 -----
Company's 401(k) plan contribution 44 ----- 275 -----
Exercise of stock options 25 ----- 120 -----
Compensation expense ----- ----- ----- -----
Accum. other comprehensive loss ----- ----- ----- -----
Write-down of securities held ----- ----- ----- -----
Issuance for conversion of pref stock 6,484 65 27,701 -----
Issuance for conversion of sub debt 4,209 42 21,146 -----
Issuance of shares frm stock offering 13,800 138 94,476 -----
Repurchase of common stock ----- ----- ----- -----
Retirement of treasury stock (09/04) (7,082) (71) (49,220) -----
Preferred dividends ----- ----- ----- (3,144)
Net earnings ----- ----- ----- 23,962
--------- --------- --------- ---------
Balance, September 30, 2004 79,205 $ 821 $ 490,063 $(181,674)
========= ========= ========= =========
Balance, December 31, 2004 79,215 $ 821 $ 490,351 $(173,244)
Issuance of rights to common stock ----- 3 1,365 -----
Company's 401(k) plan contribution 36 ----- 180 -----
Exercise of stock options 49 ----- 163 -----
Compensation expense ----- ----- ----- -----
Accum. other comprehensive income ----- ----- ----- -----
Issuance for conversion of pref stock 7,099 71 30,554 -----
Issuance cost - 2004 stock offering ----- ----- (150) -----
Issuance of shares as compensation 349 4 1,712 -----
Preferred dividends ----- ----- ----- (902)
Net earnings ----- ----- ----- 14,431
--------- --------- --------- ---------
Balance, September 30, 2005 86,748 $ 899 $ 524,175 $(159,715)
========= ========= ========= =========
Accumulated
Other Unamortized Treasury Stock
Comprehensive Deferred ------------------------
Loss Compensation Shares Cost Total
--------- --------- --------- --------- ---------
Balance, December 31, 2003 $ (7,704) $ (290) ----- $ ----- $ 184,335
Issuance of rights to common stock ----- (1,391) ----- ----- -----
Company's 401(k) plan contribution ----- ----- ----- ----- 275
Exercise of stock options ----- ----- ----- ----- 120
Compensation expense ----- 1,267 ----- ----- 1,267
Accum. other comprehensive loss (2,027) ----- ----- ----- (2,027)
Write-down of securities held 185 ----- ----- ----- 185
Issuance for conversion of pref stock ----- ----- ----- ----- 27,766
Issuance for conversion of sub debt ----- ----- ----- ----- 21,188
Issuance of shares frm stock offering ----- ----- ----- ----- 94,614
Repurchase of common stock ----- ----- (7,082) (49,291) (49,291)
Retirement of treasury stock (09/04) ----- ----- 7,082 49,291 -----
Preferred dividends ----- ----- ----- ----- (3,144)
Net earnings ----- ----- ----- ----- 23,962
--------- --------- --------- --------- ---------
Balance, September 30, 2004 $ (9,546) $ (414) ----- $ ----- $ 299,250
========= ========= ========= ========= =========
Balance, December 31, 2004 $ (1,574) $ (313) ----- $ ----- $ 316,041
Issuance of rights to common stock ----- (1,368) ----- ----- -----
Company's 401(k) plan contribution ----- ----- ----- ----- 180
Exercise of stock options ----- ----- ----- ----- 163
Compensation expense ----- 1,280 ----- ----- 1,280
Accum. other comprehensive income (11,732) ----- ----- ----- (11,732)
Issuance for conversion of pref stock ----- ----- ----- ----- 30,625
Issuance cost - 2004 stock offering ----- ----- ----- ----- (150)
Issuance of shares as compensation ----- ----- ----- ----- 1,716
Preferred dividends ----- ----- ----- ----- (902)
Net earnings ----- ----- ----- ----- 14,431
--------- --------- --------- --------- ---------
Balance, September 30, 2005 $ (13,306) $ (401) ----- $ ----- $ 351,652
========= ========= ========= ========= =========
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,
---------------------- ----------------------
2005 2004 2005 2004
-------- -------- -------- --------
Net earnings applicable to common stockholders $ 3,276 $ 7,786 $ 13,529 $ 20,818
Other comprehensive income (loss), net of tax, for unrealized losses from
hedging activities:
Unrealized holding gains (losses) arising during period (1) (14,076) (4,218) (20,481) (10,298)
Reclassification adjustments on settlement of contracts (2) 4,314 3,161 8,749 8,271
-------- -------- -------- --------
(9,762) (1,057) (11,732) (2,027)
-------- -------- -------- --------
Total comprehensive income (loss) $ (6,486) $ 6,729 $ 1,797 $ 18,791
======== ======== ======== ========
(1) net of income tax (expense) benefit $ 7,579 $ 2,271 $ 11,028 $ 5,545
(2) net of income tax expense $ (2,323) $ (1,702) $ (4,711) $ (4,453)
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, 2004, as filed with the Securities
and Exchange Commission.
The financial statements included herein as of September 30, 2005, and for the
three month and nine month periods ended September 30, 2005 and 2004, are
unaudited, and in the opinion of management, the information furnished reflects
all material adjustments, consisting of normal recurring adjustments, necessary
for a fair presentation of financial position and of the results for the interim
periods presented. Certain minor reclassifications of prior period statements
have been made to conform to current reporting practices. The results of
operations for interim periods are not necessarily indicative of results to be
expected for a full year.
2. ACCRUED LIABILITIES
Below is the detail of our accrued liabilities on our balance sheets as of
September 30, 2005 and December 31, 2004 (thousands of dollars):
SEPTEMBER 30, DECEMBER 31,
2005 2004
------- ------------
Capital Expenditures $10,178 $12,662
Bonuses 1,510 3,355
Dividends ---- 1,346
Other 3,982 4,043
------- -------
TOTAL $15,670 $21,406
======= =======
3. DEBT
CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit
facility to provide for a four-year $200 million senior secured credit facility
(the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole
lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank
of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
p.l.c., RZB Finance LLC and Standard Bank PLC completed the syndication group.
The initial borrowing base under the Credit Facility is $130 million and it was
reaffirmed by the syndication group effective as of November 1, 2005, and
continuing until the next scheduled redetermination date. As of September 30,
2005, outstanding borrowings under the Credit Facility totaled $75.1 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its
9
present value of proved oil and gas properties. In addition, the Company is
required to deliver to the lenders and maintain satisfactory title opinions
covering not less than 70% of the present value of proved oil and gas
properties. The Credit Facility also contains other restrictive covenants,
including, among other items, maintenance of certain financial ratios,
restrictions on cash dividends on Common Stock and under certain circumstances
Preferred Stock, limitations on the redemption of Preferred Stock and an
unqualified audit report on the Company's consolidated financial statements,
with which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus -1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At September 30, 2005, the three-month LIBOR interest
rate was 4.065%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
4. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK
A private placement of $66.9 million of 8.5% redeemable convertible preferred
stock was completed during May 2002. The preferred stock was convertible into
shares of the Company's Common Stock at a conversion price of $4.45 per share.
Dividends were payable semi-annually in cash or additional preferred stock. At
the option of the Company, one-third of the preferred shares could be forced to
convert to Common Stock if the closing price of the Company's Common Stock
exceeded 150% of the conversion price for 30 out of 40 consecutive trading days
on the New York Stock Exchange. The preferred stock was subject to redemption at
the option of the Company after March 2005, and mandatory redemption on March
31, 2009. During the first six months of 2005, the Company completed the
conversion of all of the remaining outstanding shares of preferred stock to
Common Stock, with $31.6 million of stated value being converted into
approximately 7.1 million shares of the Company's Common Stock.
5. COMMITMENTS AND CONTINGENCIES
LITIGATION.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated to exceed several million dollars"
for Meridian's alleged gross negligence and willful misconduct under certain
agreements concerning certain wells and property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish of Louisiana, as a result of
Meridian's satisfying a prior adverse judgment in favor of Amoco Production
Company. Meridian has filed an answer denying Hawkins' claims and asserted a
counterclaim for attorney's fees, court costs and other expenses, and for
declaratory relief that Meridian is entitled to retain the amounts that it had
been paid by Hawkins. The Company has not provided any amount for this matter in
its financial statements at September 30, 2005.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning several
fields in which the Company has had operations. The lawsuits seek injunctive
relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to
restore the plaintiffs' lands from alleged contamination and otherwise from the
defendants' oil and gas operations. The Company has not provided any amount for
these matters in the financial statements at September 30, 2005.
10
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed our insurance limits to which Meridian or any of its
subsidiaries is a party or to which any of its property is subject, other than
ordinary and routine litigation incidental to the business of producing and
exploring for crude oil and natural gas.
6. STOCKHOLDERS' EQUITY
COMMON STOCK. In August 2004, the Company completed a public offering of
13,800,000 shares of Common Stock at a price of $7.25 per share. The total
proceeds of the offering, net of issuance costs, received by the Company were
approximately $94.6 million. The Company repurchased all of the 7,082,030 shares
of its Common Stock that were beneficially owned by Shell Oil Company for $49.3
million and a portion of the remaining proceeds of that equity offering was used
to repay borrowings under the Company's senior secured credit agreement, which
resulted in an increase in funds available to the Company to accelerate planned
capital expenditures for drilling activities and related pipeline construction.
The repurchased 7,082,030 shares of Common Stock that were held in Treasury
Stock were retired as of September 30, 2004. As previously noted, during the
nine months ended September 30, 2004, 6.5 million shares of Common Stock were
issued for the conversion of the 8.5% Redeemable Convertible Preferred Stock and
4.2 million shares of Common Stock was issued for the early retirement of the 9
-1/2% Convertible Subordinated Notes. During the the first nine months of 2005,
the Company completed the conversion of all of the remaining outstanding shares
of the 8.5% Redeemable Convertible Preferred Stock with the issuance of
approximately 7.1 million shares of the Company's Common Stock.
11
7. EARNINGS PER SHARE (in thousands, except per share)
The following tables set forth the computation of basic and diluted net earnings
per share:
THREE MONTHS ENDED SEPTEMBER 30,
2005 2004
-------- -------
Numerator:
Net earnings applicable to common stockholders $ 3,276 $ 7,786
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
------- -------
Net earnings applicable to common stockholders
plus assumed conversions $ 3,276 $ 7,786
------- -------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 86,683 76,678
Effect of potentially dilutive common shares:
Warrants 4,820 4,839
Employee and director stock options 631 1,842
Redeemable preferred stock N/A N/A
------- -------
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions 92,134 83,359
======= ======
Basic earnings per share $ 0.04 $ 0.10
======= ======
Diluted earnings per share $ 0.04 $ 0.09
======= ======
NINE MONTHS ENDED SEPTEMBER 30,
2005 2004
-------- -------
Numerator:
Net earnings applicable to common stockholders $13,529 $20,818
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A
Interest on convertible subordinated notes ----- 270
------- -------
Net earnings applicable to common stockholders
plus assumed conversions $13,529 $21,088
------- -------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 83,771 69,690
Effect of potentially dilutive common shares:
Warrants 4,701 4,439
Employee and director stock options 865 1,584
Convertible subordinated notes ----- 1,139
Redeemable preferred stock N/A N/A
------- -------
Denominator for diluted earnings per
share - weighted-average shares outstanding
and assumed conversions 89,337 76,852
======= ======
Basic earnings per share $ 0.16 $ 0.30
======= ======
Diluted earnings per share $ 0.15 $ 0.27
======= ======
12
8. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company addresses market risk by selecting instruments with value
fluctuations which correlate strongly with the underlying commodity being
hedged. The Company enters into derivative contracts to hedge the price risks
associated with a portion of anticipated future oil and gas production. While
the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at or
prior to expiration or are exchanged for physical delivery contracts. The
Company does not obtain collateral to support the agreements, but monitors the
financial viability of counter-parties and believes its credit risk is minimal
on these transactions. In the event of nonperformance by the counter-party, the
Company would be exposed to price risk. The Company has some risk of accounting
loss since the price received for the product at the actual physical delivery
point may differ from the prevailing price at the delivery point required for
settlement of the hedging transaction.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various
derivative contracts. These contracts allow the Company to predict with greater
certainty the effective oil and natural gas prices to be received for hedged
production. Although derivatives often fail to achieve 100% effectiveness for
accounting purposes, these derivative instruments continue to be highly
effective in achieving the risk management objectives for which they were
intended. These contracts have been designated as cash flow hedges as provided
by Statement of Financial Accounting Standards ("SFAS") 133 and any changes in
fair value are recorded in other comprehensive income until earnings are
affected by the variability in cash flows of the designated hedged item. Any
changes in fair value resulting from the ineffectiveness of the hedge are
reported in the consolidated statement of operations as a component of revenues.
The Company recognized a gain related to hedge ineffectiveness of approximately
$0.1 million during the three months and a loss of approximately $0.4 million
during the nine months ended September 30, 2005, and none during the three and
nine months ended September 30, 2004.
The estimated September 30, 2005 fair value of the Company's oil and natural gas
derivatives was a net unrealized loss of $20.5 million ($13.3 million net of
tax) which is recorded in Accumulated Other Comprehensive Loss on the Company's
consolidated balance sheet. Based upon September 30, 2005 oil and natural gas
commodity prices, approximately $19.7 million of the loss deferred in other
comprehensive income could potentially lower gross revenues over the next twelve
months. The derivative contracts expire at various dates through July 31, 2007.
Net settlements under these derivative contracts reduced oil and natural gas
revenues by $5,517,000 and $4,863,000 for the three months ended September 30,
2005 and 2004, respectively, and by $12,340,000 and $12,724,000 for the nine
months ended September 30, 2005 and 2004, respectively, as a result of hedging
transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 26% of the proved developed natural gas production and 28% of the
proved developed oil production during the respective terms of the derivative
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.
The fair value of the hedging agreements is recorded on our consolidated balance
sheet as separately identified assets or liabilities, except for $451 thousand
included in Other Assets. The estimated fair value of our hedging agreements as
of September 30, 2005, is provided below:
13
Swap / Floor Ceiling Fair Value
Notional Price Price Sept 30, 2005
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ --------------
NATURAL GAS (MMBTU)
Oct 2005 Swap 350,000 $ 6.34 N/A $ (2,646)
Oct 2005 Collar 350,000 $ 6.50 $ 7.90 (2,102)
Nov 2005 - Mar 2006 Collar 2,980,000 $ 7.50 $ 11.25 (10,381)
Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $ 14.50 (47)
--------
Total Natural Gas (15,176)
--------
CRUDE OIL (BBLS)
Oct 2005 - Jul 2006 Collar 173,000 $ 37.50 $ 47.50 (3,356)
Oct 2005 - Jul 2006 Collar 33,000 $ 40.00 $ 50.00 (571)
Aug 2006 - Jul 2007 Collar 168,000 $ 50.00 $ 74.00 (521)
--------
Total Crude Oil (4,448)
--------
$(19,624)
========
As of September 30, 2005, the Company had designated a natural gas hedge related
to the first 380,000 Mmbtu produced and sold from its Biloxi Marshlands ("BML")
project area during September 2005. As previously announced, Hurricane Katrina
caused a production disruption during September 2005 in the Company's BML
project area, whereby all of the Company's natural gas production was curtailed
during the hedge period. Since the Company was unable to deliver natural gas, a
hedging loss of approximately $1.1 million was deferred until production was
re-established in October 2005, as per the Financial Accounting Standards
Board's ("FASB") SFAS 133 Implementation Issue No. G3.
9. STOCK-BASED COMPENSATION
SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure,"
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. As provided
for under SFAS 123, there has been no amount of compensation expense recognized
for the Company's stock option plans. The Company accounts for stock-based
compensation using the intrinsic value method prescribed in Accounting
Principles Board ("APB") Opinion 25, "Accounting for Stock Issued to Employees."
Compensation expense is recorded for restricted stock awards over the requisite
vesting periods based upon the market value on the date of the grant. No
stock-based compensation expense was recorded in the three or nine month periods
ended September 30, 2005 and 2004.
The following is a reconciliation of reported earnings and earnings per share as
if the Company used the fair value method of accounting for stock-based
compensation. Fair value is calculated using the Black-Scholes option-pricing
model.
14
(In thousands, except per share data)
Three Months Ended September 30,
-------------------------------------
2005 2004
--------- ---------
Net earnings applicable to common stockholders as reported $ 3,276 $ 7,786
Stock-based compensation (expense) benefit determined under
fair value method for all awards, net of tax (64) (66)
--------- ---------
Net earnings applicable to common stockholders pro forma $ 3,212 $ 7,720
========= =========
Basic earnings per share:
As reported $ 0.04 $ 0.10
Pro forma $ 0.04 $ 0.10
Diluted earnings per share:
As reported $ 0.04 $ 0.09
Pro forma $ 0.04 $ 0.09
(In thousands, except per share data)
Nine Months Ended September 30,
-------------------------------------
2005 2004
--------- ---------
Net earnings applicable to common stockholders as reported $ 13,529 $ 20,818
Stock-based compensation expense determined under
fair value method for all awards, net of tax (162) (74)
--------- ---------
Net earnings applicable to common stockholders pro forma $ 13,367 $ 20,744
========= =========
Basic earnings per share:
As reported $ 0.16 $ 0.30
Pro forma $ 0.16 $ 0.30
Diluted earnings per share:
As reported $ 0.15 $ 0.27
Pro forma $ 0.15 $ 0.27
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
No. 95 "Statement of Cash Flows". This statement addresses the accounting for
share-based payment transactions in which an enterprise receives employee
services in exchange for (a) equity instruments of the enterprise or (b)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
The statement would eliminate the ability to account for share-based
compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued
to Employees," and generally would require instead that such transactions be
accounted for using a fair-value-based method. This statement will be effective
for the Company for interim periods beginning after December 15, 2005. The
impact on the results of operations would be similar to the pro forma
disclosures made above.
10. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
The fair value of asset
15
retirement obligation liabilities has been calculated using an expected present
value technique. Fair value, to the extent possible, should include a market
risk premium for unforeseeable circumstances. No market risk premium was
included in the Company's asset retirement obligations fair value estimate since
a reasonable estimate could not be made. When the liability is initially
recorded, the entity increases the carrying amount of the related long-lived
asset. Over time, accretion of the liability is recognized each period, and the
capitalized cost is amortized over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. This standard requires
the Company to record a liability for the fair value of our dismantlement and
abandonment costs, excluding salvage values.
The following table describes the change in the Company's asset retirement
obligations for the nine months ended September 30, 2005, and for the year ended
December 31, 2004 (thousands of dollars):
Asset retirement obligation at December 31, 2003 $ 4,102
Additional retirement obligations recorded in 2004 1,051
Settlements during 2004 (972)
Revisions to estimates during 2004 4,842
Accretion expense for 2004 601
--------
Asset retirement obligation at December 31, 2004 9,624
Additional retirement obligations recorded in 2005 760
Settlements during 2005 (182)
Revisions to estimates during 2005 (226)
Accretion expense for 2005 798
--------
Asset retirement obligation at September 30, 2005 $ 10,774
========
11. NEW ACCOUNTING PRONOUNCEMENTS
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
No. 95, "Statement of Cash Flows." This statement addresses the accounting for
share-based payment transactions in which an enterprise receives employee
services in exchange for (a) equity instruments of the enterprise or (b)
liabilities that are based on the fair value of the enterprise's equity
instruments or that may be settled by the issuance of such equity instruments.
The statement would eliminate the ability to account for share-based
compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued
to Employees," and generally would require instead that such transactions be
accounted for using a fair-value-based method. This statement will be effective
for the Company for interim periods beginning after December 15, 2005. The
impact on the results of operations would be similar to the pro forma
disclosures presented in Note 9.
In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for
Conditional Asset Retirement Obligations." This interpretation clarifies the
definition and treatment of conditional asset retirement obligations as
discussed in FASB No. 143, "Accounting for Asset Retirement Obligations." A
conditional asset retirement obligation is defined as an asset retirement
activity in which the timing and/or method of settlement are dependent on future
events that may be outside the control of the Company. FIN No. 47 states that a
Company must record a liability when incurred for conditional asset retirement
obligations if the fair value of the obligation is reasonably estimable. This
interpretation is intended to provide more information about long-lived assets,
more information about future cash outflows for these obligations and more
consistent recognition of these liabilities. FIN No. 47 is effective for fiscal
years ending after December 15, 2005. This interpretation does not have any
impact to the Company's financial position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections -- a replacement of APB No. 20 and FASB No. 3." In order to enhance
financial reporting consistency between periods, SFAS No. 154 modifies the
requirements for the accounting and reporting of the direct effects of changes
in
16
accounting principles. Under APB No. 20, the cumulative effect of voluntary
changes in accounting principle was recognized in Net Income in the period of
the change. Unlike the treatment previously prescribed by APB No. 20,
retrospective application is now required, unless it is not practical to
determine the specific effects in each period or the cumulative effect. If the
period specific effects cannot be determined, it is required that the new
accounting principle must be retrospectively applied in the earliest period
possible to the balance sheet accounts and a corresponding adjustment be made to
the opening balance of retained earnings or another equity account. If the
cumulative effect cannot be determined, it is necessary to apply the new
accounting principles prospectively at the earliest practical date. If it is not
feasible to retrospectively apply the change in principle, the reason that this
is not possible and the method used to report the change are required to be
disclosed. The statement also provides that changes in accounting for
depreciation, depletion or amortization should be treated as changes in
accounting estimate inseparable from a change in an accounting principle and
that disclosure of the preferability of the change is required. SFAS No. 154 is
effective for accounting changes made in fiscal years beginning after December
15, 2005.
17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following is a discussion of The Meridian Resource Corporation and its
subsidiaries' ("Meridian" or the "Company") financial operations for the three
and nine months ended September 30, 2005 and 2004. The Company's consolidated
financial statements included in this report, as well as our Annual Report on
Form 10-K for the year ended December 31, 2004 (and the notes attached thereto),
should be read in conjunction with this discussion.
GENERAL.
Management believes the Company's financial condition and operations are on
sound footing as evidenced by the following:
o Average daily production is currently approximately 73.2 Mmcfe/d, or
approximately 105% of the pre-Hurricane Katrina level with more to be
added in the near term;
o Positive earnings have been maintained in the face of extremely
difficult conditions during the third quarter;
o Solid cash flows and liquidity, combined with low debt ratios maintain
financial flexibility;
o And a balanced inventory of exploration plays continues to allow
the Company to grow production.
Meridian ended 2004 and entered 2005 with greater than normal production
declines related primarily to three of the Company's larger producing wells
being shut in for workover and operational issues, compounded by a series of
exploration dry holes drilled in an effort to extend the Company's Biloxi
Marshlands prospect area beyond the geological and geographical limits of the
traditional shallower Cris I sand section. Immediate actions were taken to
address the production issues and the trend began to reverse during the second
quarter as a result of several exploration successes in two of the Company's
primary regions of exploration and development--Turtle Bayou/Ramos Complex area
with discoveries at Turtle Island, Turtle Cove, Bayou Chene, Northwest Bayou
Chene, Bayou Black and Turtle Shell; and in Biloxi Marshlands project area with
new discoveries in the northeast quadrant at String of Pearls and in the extreme
southwest quadrant at Bayou Gentilly. The exploration program remained intact
with the identification of a series of offsets to the new discoveries with the
necessary cash flows available to implement the Company's capital spending
program during the balance of the third and fourth quarters of 2005.
Poised to move forward with the second-half drilling program, the Company was
confronted with major hurdles that began with Hurricane Dennis during June 2005
which left workover operations 1,000 feet shy of the target depth and days away
from the potential of returning production to the Biloxi Marshlands 1-2 well at
its prior rate or 7.5 Mmcfe/d (3.5 Mmcfe/d net). The hurdles culminated with the
complete destruction of almost all of the Company's production facilities in the
Biloxi Marshlands project area as the eye of Hurricane Katrina passed directly
over the area. What followed in late August 2005 was a series of some of the
greatest challenges in the history of the Gulf Coast and Meridian--the
devastation of Hurricanes Katrina and Rita.
Beginning August 28, 2005, the Company shut in all production in all effected
areas in anticipation of Hurricane Katrina and removed all personnel from the
field. With the support and assistance of its senior bank group, the Company's
unutilized borrowing capacity ($55 million) allowed it to meet the challenges
head on, to manage the problems of people, equipment, boats, barges, quarters,
production equipment, and fabrication. Meridian began to restore lost production
only forty-five (45) days after operations were initiated, beginning first with
the return of production to the Company's Biloxi Marshlands Facility #1,
followed by the reinstatement at the Biloxi Marshlands Facilities #2, #3 and #4,
the successful recompletion operations at the SL 16049 well in the Ramos Complex
and the addition of the Bayou Chene and Northwest Bayou Chene discoveries, with
more to come following completion of pipeline and production facilities at
Turtle Shell, Bayou Black, String of Pearls, Hornets Nest, and Bayou Gentilly.
At present, without the addition of the above wells or full compression at all
of the Biloxi facilities, the Company is currently producing 105% of pre-Katrina
production levels.
18
To all who served to assist us in this effort, we are and will be forever
grateful. These include our entire staff and contract personnel, especially the
operations and production group, field staff experiencing first-hand their own
personal losses, but who, after protecting their families, immediately (within
hours and days of the storm's passing) returned to the field to bring our
production back on stream. Our thanks also go to all of our service companies
and suppliers of equipment, services, supplies and fabrication, and construction
facilities.
The financial restructuring the Company completed over the past several years
allowed the Company to continue its plans for growth in spite of the fact that
approximately 50% of the Company's existing production was shut-in for a
significant portion of the third quarter of 2005. The Company's debt position
remained low and the Company was able to realize a larger percentage of the
commodity price increases experienced during the quarter as a result of
expiration of the lower oil and gas hedge position.
During the course of the first nine months of 2005, Meridian's exploration
drilling activities were focused on extending the Biloxi Marshlands exploration
play with the acquisition of the final 140 square miles of 3-D seismic data in
the southwestern quadrant of its 400,000-acre option/lease acreage position and
the drilling of extension wells to test and analyze the limits of the aerial
extent of the play for the timely exercise of our lease options during December
2005.
These activities focused on developing exploration concepts beyond the
traditional Cris I type targets, with the objective of extending our
understanding of all hydrocarbon indicators or signatures within the play and to
the extreme limits of all areas within the proprietary 3-D survey. We were
successful in establishing new production from new sands in the northeast
quadrant of the acreage with the discovery of the String of Pearls Deltaic
prospect well and then to the extreme southwest region of its acreage with the
discovery of the Bayou Gentilly prospect in the pressured Cris I section. As a
result, additional prospective acreage was identified and acquired for future
drilling operations now scheduled for the remainder of 2005 and 2006.
Information gained from the Company's drilling activities and newly acquired and
reprocessed 3-D seismic data in the region has resulted in an increased
knowledge base for future drilling.
Prior to the interruptions in drilling and production caused by Hurricanes
Katrina and Rita, we had scheduled the drilling of five additional wells in the
area near the String of Pearls prospect well beginning with the Gato del Sol
prospect. Although delayed, it is anticipated that we will resume drilling
activities in the region upon the return of the Company's drilling rig during
the fourth quarter 2005, with expectations to continue to drill one well per
month in the Biloxi Marshlands project area through 2006. In addition, the
Company has completed the development of its deeper prospects and anticipates
beginning to drill the first such prospect during the first quarter 2006.
Multiple stacked pay sands with three-way and four-way closures have been
identified using the Company's reprocessed data applications confirming the
existence of closures and sand respectively in several of the targeted
objectives. Potential unrisked reserves range between 250 Bcfe and 750 Bcfe from
two of the three proposed wells.
Since inception of the Biloxi Marshlands project area, Meridian has expended
approximately $184 million in the Biloxi Marshlands project area on lease
options, leases, 3-D seismic acquisitions and processing, exploration drilling
and completion activities, pipelines and production facilities. We have drilled
35 wells, completing 21 wells for a success rate of approximately 60% in
multiple sand sections including the Deltaic, Cris I, both pressured and
nonpressured, and Rob L sands. We have received a return of our investment of
approximately $191 million and currently are producing approximately 31.8
Mmcfe/d (net) or 90% of pre-storm levels from the Biloxi Marshlands project
area, not including
19
production from the String of Pearls, Hornets Nest and Bayou Gentilly wells and
without full rate deliveries at all other facilities because full compression
has not been reinstated to date.
In general, production in Biloxi has outperformed predictions at locations with
larger reservoirs and generally met expectations or disappointed expectations at
smaller reservoir locations. The Company continues to increase its knowledge in
the area as additional wells are drilled and placed on production in the region
with expectations to improve our success ratios as we continue to exploit the
area's reserves. The Company believes that no one has as much experience or
knowledge about drilling in this region based on the newly acquired technical
data and information in our exclusive possession. As a result, we believe that
we have an advantage over our competition in the region for development of
future opportunities after the exercise of our lease options in December 2005.
We will be the only exploration company with the fully processed and merged
proprietary 3-D data over the entire acreage position without seismic gaps in
the data.
In addition to the activities in our Biloxi Marshlands play, we began the
drilling of our Turtle Bayou/Ramos Complex area patterned after our previously
discovered Thornwell field and the Biloxi Marshlands models of lower risk,
multiple-well exploration in areas where reserves have either been overlooked or
bypassed by others in the area. During 2005, we successfully drilled and
completed 6 wells with 2 dry holes. The most recent discovery was the Company's
Turtle Shell prospect which was recently tested up to a rate of 4 Mmcfe/d with
no water, beyond which point it was unnecessary to produce additional gas into
the atmosphere prior to turning the well to production upon completion of
pipeline tie-ins. Operations in this area were affected by the hurricanes but
not to the same extent experienced in Biloxi Marshlands. While we were delayed
with our operations and production because of shutting in producing wells and
mobilizing people and drilling/workover rigs to safe harbor prior to the storms
arrival, we have completed the drilling of the Turtle Shell prospect well and
the successful recompletion of the SL16049 well, returning the well to
production at a rate of approximately 5.1 Mmcfe/d (net).
With the addition of the SL 16049 well and the addition of the Bayou Chene
discoveries, current production post Hurricanes Katrina and Rita from the Turtle
Bayou/Ramos Complex wells net to the Company has reached 29.2 Mmcfe/d (net), or
155% of pre-storm production levels. These rates do not include the Turtle Shell
prospect well which is expected to be on line and producing within 30 days. We
have identified multiple additional prospects in this new area of exploration
and are currently drilling the Company's Bayou Lawrence prospect at
approximately 8,300 feet measured depth ("MD") with a target depth of 10,900
feet MD. Depending on the Company's continued success, it has identified a
minimum of 3-8 additional prospects in this area and will continue exploration
activities to develop other similar leads in the immediate area.
Other activities during the past nine months include the previously reported
joint venture participation in the East Texas Woodbine play, further extending
the Company's seismic-based exploration strategy to areas that we believe will
not only add to our reserve base but lengthen our overall reserve life ratios.
Since acquiring the acreage positions in conjunction with our partner, we have
added additional acreage under identified prospects and have permitted three
drilling locations as we await two rigs that have been contracted to drill the
first two wells, with one rig anticipated to remain and drill additional
follow-on wells based on results. Depending on the Company's success in the
area, we have budgeted the drilling of up to nine wells for the remainder of
2005 and 2006.
Meridian continues to expand its domestic exploration program to insure a
balance of higher rate wells delivering earlier cash flows typically found in
its core area of the Gulf Coast region of south Louisiana and southeast Texas
with longer lived conventional and unconventional plays that provide the Company
with a longer lived reserve base and multiple-well development opportunities
where the earlier cash flows can be deployed to add steady growth in reserves
over the long term. We are pleased with our initial efforts in this area and
look forward to continued success in this extension of the Company's business
plan.
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,
2005, was $43.92 per barrel compared to $30.26 per barrel for the three months
ended September 30, 2004, and $31.14 per barrel for the three months ended June
30, 2005. Our average natural gas price (after adjustments for hedging
activities) for the three months ended September 30, 2005, was $7.32 per Mcf
compared to $5.58 per Mcf for the three months ended September 30, 2004, and
$6.63 per Mcf for the three months ended June 30, 2005. Fluctuations in
prevailing prices for oil and natural gas have several important consequences to
us, including affecting the level of cash flow received from our producing
properties, the timing of exploration of certain prospects and our access to
capital markets, which could impact our revenues, profitability and ability to
maintain or increase our exploration and development program.
20
CRITICAL ACCOUNTING POLICIES AND ESTIMATES. The Company's discussion and
analysis of its financial condition and results of operation are based upon
consolidated financial statements, which have been prepared in accordance with
accounting principles generally accepted and adopted in the United States. The
preparation of these financial statements requires the Company to make estimates
and judgments that affect the reported amounts of assets, liabilities, revenues
and expenses. See the Company's Annual Report on Form 10-K for the year ended
December 31, 2004, for further discussion.
21
RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2004
OPERATING REVENUES. Third quarter 2005 oil and natural gas revenues, which
include oil and natural gas hedging activities (see Note 8 of Notes to
Consolidated Financial Statements), decreased $16.3 million (31%) as compared to
third quarter 2004 revenues due to a 48% decrease in production volumes
primarily due to natural production declines and hurricane-related losses (see
"General" above), partially offset by a 34% increase in average commodity prices
on a natural gas equivalent basis. Our average daily production decreased from
105.1 Mmcfe during the third quarter of 2004 to 54.5 Mmcfe for the third quarter
of 2005. Oil and natural gas production volume totaled 5,010 Mmcfe for the third
quarter of 2005, compared to 9,671 Mmcfe for the comparable period of 2004.
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the three months ended September 30, 2005
and 2004:
THREE MONTHS ENDED
SEPTEMBER 30, INCREASE
2005 2004 (DECREASE)
------- ------- -------
Production Volumes:
Oil (Mbbl) 203 320 (37%)
Natural gas (MMcf) 3,790 7,753 (51%)
Mmcfe 5,010 9,671 (48%)
Average Sales Prices:
Oil (per Bbl) $ 43.92 $ 30.26 45%
Natural gas (per Mcf) $ 7.32 $ 5.58 31%
Mmcfe $ 7.32 $ 5.48 34%
Operating Revenues (000's):
Oil $ 8,916 $ 9,683 (8%)
Natural gas 27,748 43,268 (36%)
------- -------
Total Operating Revenues $36,664 $52,951 (31%)
======= =======
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $0.3 million (12%) to $3.4 million during the third quarter of 2005,
compared to $3.1 million in 2004. On a unit basis, lease operating expenses
increased $0.36 per Mcfe to $0.68 per Mcfe for the third quarter of 2005 from
$0.32 per Mcfe for the third quarter of 2004. The increase in per unit cost is a
reflection of lower production volumes between the two periods, as explained
above.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes totaled $2.2
million for both the third quarter of 2005 and 2004. A decrease in oil and
natural gas production was offset by an increase in oil prices and a higher
natural gas tax rate. Meridian's oil and natural gas production is primarily
from Louisiana, and is therefore subject to Louisiana severance tax. The
severance tax rates for Louisiana are 12.5% of gross oil revenues and were
$0.252 per Mcf for natural gas, an increase from $0.208 per Mcf for the third
quarter of 2004. On an equivalent unit of production basis, severance and ad
valorem taxes increased to $0.44 per Mcfe from $0.23 per Mcfe for the comparable
three-month period.
22
DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $8.7
million during the third quarter of 2005 to $19.7 million. This was primarily
the result of the decrease in oil and natural gas production, partially offset
by an increase in the depletion rate as compared to the 2004 period. The Company
revised its earlier reserve estimates associated the Thibodaux #3 well in the
Ramos field based on the well's performance, resulting in a higher depletion and
depreciation rate coupled with the addition of costs related to unsuccessful
wells drilled during 2005. On a unit basis, depletion and depreciation expense
increased by $1.00 per Mcfe, to $3.94 per Mcfe for the three months ended
September 30, 2005, compared to $2.94 per Mcfe for the same period in 2004.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was
essentially flat, between the corresponding periods. On an equivalent unit of
production basis, general and administrative expenses increased to $0.79 per
Mcfe for the third quarter of 2005 compared to $0.42 per Mcfe for the comparable
2004 period. The increase in per unit cost is a reflection of lower production
volumes between the two periods, as explained above.
HURRICANE DAMAGE REPAIRS. This expense of $750 thousand is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
insurance deductible.
INTEREST EXPENSE. Interest expense decreased $0.4 million (26%), to $1.2 million
for the third quarter of 2005 in comparison to the third quarter of 2004. The
decrease is primarily a result of the reduction in long-term debt.
NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2004
OPERATING REVENUES. Oil and natural gas revenues during the nine months ended
September 30, 2005, decreased $18.3 million (12%) as compared to the revenues
for the nine months ended September 30, 2004, due to a 28% decrease in
production volumes primarily from natural production declines and partially from
the effects of hurricanes (see "General" above), partially offset by a 21%
increase in average commodity prices on a natural gas equivalent basis. Our
average daily production decreased from 99.5 Mmcfe during the first nine months
of 2004 to 72.2 Mmcfe for the first nine months of 2005. Oil and natural gas
production volume totaled 19,706 Mmcfe for the first nine months of 2005,
compared to 27,269 Mmcfe for the comparable period of 2004.
23
The following table summarizes the Company's operating revenues, production
volumes and average sales prices for the nine months ended September 30, 2005
and 2004:
NINE MONTHS ENDED
SEPTEMBER 30, INCREASE
2005 2004 (DECREASE)
-------- --------- ----------
Production Volumes:
Oil (Mbbl) 680 977 (30%)
Natural gas (MMcf) 15,623 21,409 (27%)
Mmcfe 19,706 27,269 (28%)
Average Sales Prices:
Oil (per Bbl) $ 36.03 $ 27.61 30%
Natural gas (per Mcf) $ 6.81 $ 5.71 19%
Mmcfe $ 6.64 $ 5.47 21%
Operating Revenues (000's):
Oil $ 24,519 $ 26,957 (9%)
Natural gas 106,363 122,199 (13%)
-------- ---------
Total Operating Revenues $130,882 $149,156 (12%)
======== =========
OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis
increased $3.4 million (39%) to $12.2 million during the first nine months of
2005, compared to $8.8 million in 2004. On a unit basis, lease operating
expenses increased $0.30 per Mcfe to $0.62 per Mcfe for the first nine months of
2005 from $0.32 per Mcfe for the first nine months of 2004. Oil and gas
operating expenses increased due to additional operating expenses associated
with the increase in wells and facilities in the Biloxi Marshlands project area,
and to increased workover-related expenses of approximately $1.8 million,
primarily at Weeks Island, Ramos and various offshore fields.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.3
million (5%) to $6.7 million for the first nine months of 2005, compared to $7.0
million during the same period in 2004 primarily because of a decrease in oil
and natural gas production, partially offset by an increase in oil prices and a
higher natural gas tax rate. Meridian's oil and natural gas production is
primarily from Louisiana, and is therefore subject to Louisiana severance tax.
The severance tax rates for Louisiana are 12.5% of gross oil revenues and were
$0.252 per Mcf (effective July 1, 2005) for natural gas. For the first six
months of 2005 and the last six months of 2004, the rate was $0.208 per Mcf for
natural gas, an increase from $0.171 per Mcf for the first half of 2004. On an
equivalent unit of production basis, severance and ad valorem taxes increased to
$0.34 per Mcfe from $0.26 per Mcfe for the comparable nine-month period.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $6.9
million (9%) during the first nine months of 2005 to $70.5 million, from $77.4
million for the same period of 2004. This was primarily the result of the
decline in oil and natural gas production, partially offset by an increase in
the depletion rate as compared to the 2004 period. During the second quarter of
2005, the Company suspended operations to re-drill a well on its North Turtle
Bayou prospect after unsuccessful attempts to reestablish production from the
well. During the third quarter of 2005, the Company re-evaluated the Thibodaux
#1 well in the Ramos field based on the well's performance. As a result, the
Company revised its earlier reserve estimates associated with these wells
resulting in a higher depletion and depreciation rate coupled with the addition
of costs related to unsuccessful wells drilled during 2005. On a unit basis,
depletion and depreciation expense increased by $0.74 per Mcfe, to $3.58 per
Mcfe for the nine months ended September 30, 2005, compared to $2.84 per Mcfe
for the same period in 2004.
24
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$2.6 million to $13.3 million compared to $10.7 million for 2004. The increase
was primarily the result of increased professional services, accounting fees and
increased operating activities. On an equivalent unit of production basis,
general and administrative expenses increased $0.29 per Mcfe to $0.68 per Mcfe
for the first nine months of 2005 compared to $0.39 per Mcfe for the comparable
2004 period.
HURRICANE DAMAGE REPAIRS. This expense of $750 thousand is related to damages
incurred from hurricanes Katrina and Rita, primarily related to the Company's
insurance deductible.
INTEREST EXPENSE. Interest expense decreased $2.3 million (41%), to $3.3 million
for the first nine months of 2005 in comparison to the first nine months of
2004. The decrease is a result of the reduction in long-term debt.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the first nine months of 2005, Meridian's capital
expenditures were internally financed with cash from operations. As of September
30, 2005, the Company had a cash balance of $15.8 million and a working capital
deficit of $23.1 million. This deficit was made up primarily of a $19.6 million
net current liability associated with price risk management activities which
will be offset by future revenues. Management's strategy is to grow the Company
by taking advantage of the strong asset base built over the years and to add
reserves through the drill bit while maintaining a disciplined approach to
costs. Where appropriate, the Company will allocate excess cash above capital
expenditures to reduce leverage.
CASH FLOWS. Net cash provided by operating activities was $96.4 million for the
nine months ended September 30, 2005, as compared to $127.1 million for the same
period in 2004. The decrease of $30.6 million was primarily due to a reduction
in revenues from oil and natural gas of $18.3 million and a reduction in accrued
expenses in the first nine months of 2005 from the first nine months of 2004.
Net cash used in investing activities was $103.9 million during the nine months
ended September 30, 2005, versus $100.0 million in the first nine months of
2004. The increase in capital expenditures of $3.9 million was primarily
associated with drilling and related activities in the Biloxi Marshlands project
area and the greater Ramos Complex.
Cash flows used in financing activities during the first nine months of 2005
were $1.1 million, compared to cash used in financing activities of $11.5
million during the first nine months of 2004. This reduction in cash used in
financing activities was primarily due to reduced preferred stock dividends
coupled with the reduction in debt repayments. With the preferred stock
conversions in 2005, the Company will see an annual $2.6 million reduction of
dividend payments.
CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit
facility to provide for a four-year $200 million senior secured credit facility
(the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole
lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank
of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
p.l.c., RZB Finance LLC and Standard Bank PLC completed the syndication group.
The initial borrowing base under the Credit Facility is $130 million and it has
been reaffirmed by the syndication group effective November 1, 2005. As of
September 30, 2005, outstanding borrowings under the Credit Facility totaled
$75.1 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company, have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's
25
subsidiaries and by a first priority lien on not less than 75% (95% in the case
of an event of default) of its present value of proved oil and gas properties.
In addition, the Company is required to deliver to the lenders and maintain
satisfactory title opinions covering not less than 70% of the present value of
proved oil and gas properties. The Credit Facility also contains other
restrictive covenants, including, among other items, maintenance of certain
financial ratios, restrictions on cash dividends on Common Stock and under
certain circumstances Preferred Stock, limitations on the redemption of
Preferred Stock and an unqualified audit report on the Company's consolidated
financial statements, all of which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus -1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At September 30, 2005, the three-month LIBOR interest
rate was 4.065%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. A private placement of $66.85
million of 8.5% redeemable convertible preferred stock was completed during May
2002. The preferred stock was convertible into shares of the Company's Common
Stock at a conversion price of $4.45 per share. Dividends were payable
semi-annually in cash or additional preferred stock. At the option of the
Company, one-third of the preferred shares could be forced to convert to Common
Stock if the closing price of the Company's Common Stock exceeded 150% of the
conversion price for 30 out of 40 consecutive trading days on the New York Stock
Exchange. The preferred stock was subject to redemption at the option of the
Company after March 2005, and mandatory redemption on March 31, 2009. During the
first six months of 2005, the Company completed the conversion of all of the
remaining outstanding shares of preferred stock to Common Stock, with $31.6
million of stated value being converted into approximately 7.1 million shares of
the Company's Common Stock.
OIL AND NATURAL GAS HEDGING ACTIVITIES. The Company addresses market risk by
selecting instruments whose value fluctuations correlate strongly with the
underlying commodity being hedged. The Company enters into 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 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 this nine month period
approximated $103.8 million. Although the Company plans to continue additional
drilling during the remainder of 2005, such operations will depend primarily on
achieving anticipated cash flows, permitting of wells and the availability of
suitable drilling rigs. Meridian recently completed the final field work on its
3-D seismic survey at its Biloxi Marshlands acreage and preliminary indications
are that a number of additional drilling locations are present in the area
encompassing the new survey which will form the basis for its future drilling
activities during 2006.
26
Based on internal projections, using its internal risked analysis of production
based on an expected capital expenditures program for 2005 of $139 million, the
Company believes that it can further improve its balance sheet while, at the
same time, continuing its scheduled capital expenditure program, drilling 15 to
20 low-risk wells during 2005 and acquiring and re-processing additional 3-D
seismic data over its Biloxi Marshlands project and other exploration areas
targeted for exploration growth.
DIVIDENDS. It is our policy to retain existing cash for reinvestment in our
business, and therefore, we do not anticipate that dividends will be paid with
respect to the Common Stock in the foreseeable future. During May 2002, the
Company completed the private placement of approximately $67 million of 8.5%
Redeemable Convertible Preferred Stock and dividends were payable semi-annually.
A semi-annual cash dividend of $1.3 million was paid in January 2005. A final
cash dividend of $0.9 million was paid during the second quarter of 2005.
During the first six months of 2005, the Company completed the conversion of all
of the remaining outstanding shares of the 8.5% Redeemable Convertible Preferred
Stock to Common Stock, with $31.6 million of stated value being converted into
approximately 7.1 million shares of the Company's Common Stock. As a result of
these conversions in 2005, the Company will realize an annual cash savings of
approximately $2.6 million on the Preferred Stock dividends.
FORWARD-LOOKING INFORMATION
From time to time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involve risk and uncertainty. These forward-looking statements may
include, but are not limited to exploration and seismic acquisition plans,
anticipated results from current and future exploration prospects, future
capital expenditure plans, anticipated results from third party disputes and
litigation, expectations regarding compliance with our credit facility, the
anticipated results of wells based on logging data and production tests, future
sales of production, earnings, margins, production levels and costs, market
trends in the oil and natural gas industry and the exploration and development
sector thereof, environmental and other expenditures and various business
trends. Forward-looking statements may be made by management orally or in
writing including, but not limited to, the Management's Discussion and Analysis
of Financial Condition and Results of Operations section and other sections of
our filings with the Securities and Exchange Commission under the Securities Act
of 1933, as amended, and the Securities Exchange Act of 1934, as amended.
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following:
CHANGES IN THE PRICE OF OIL AND NATURAL GAS. The prices we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that we do not 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
27
addition, we are subject to other operating and production risks such as title
problems, weather conditions, compliance with government permitting
requirements, shortages of or delays in obtaining equipment, reductions in
product prices, limitations in the market for products, litigation and disputes
in the ordinary course of business. Although we maintain insurance coverage
considered to be customary in the industry, we are not fully insured against
certain of these risks either because such insurance is not available or because
of high premium costs. We cannot predict if or when any such risks could affect
our operations. The occurrence of a significant event for which we are not
adequately insured could cause our actual results to differ from those reflected
in our forward-looking statements.
DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit
a prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analysis, production data and engineering
studies, which may be imprecise. Therefore, we cannot assure you that all of our
drilling activities will be successful or that we will not drill uneconomical
wells. The occurrence of unexpected drilling results could cause the actual
results to differ from those reflected in our forward-looking statements.
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality available of
data and of engineering and geological interpretation and judgment. Reserve
estimates may be imprecise and may be expected to change as additional
information becomes available. There are numerous uncertainties inherent in
estimating quantities and values of proved reserves and in projecting future
rates of production and timing of development expenditures, including many
factors beyond our control. The quantities of oil and natural gas that we
ultimately recover, production and operating costs, the amount and timing of
future development expenditures and future oil and natural gas sales prices may
differ from those assumed in these estimates. Significant downward revisions to
our existing reserve estimates could cause the actual results to differ from
those reflected in our forward-looking statements.
BORROWING BASE FOR THE CREDIT FACILITY. The Credit Agreement with Fortis Capital
Corp. is presently scheduled for borrowing base redetermination dates on a
semi-annual basis with the next such redetermination scheduled for April 30,
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.
28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is currently exposed to market risk from hedging contracts changes
and changes in interest rates. A discussion of the market risk exposure in
financial instruments follows.
INTEREST RATES
We are subject to interest rate risk on our long-term fixed interest rate debt
and variable interest rate borrowings. Our long-term borrowings primarily
consist of borrowings under the Credit Facility. Since interest charged on
borrowings under the Credit Facility floats with prevailing interest rates
(except for the applicable interest period for Eurodollar loans), the carrying
value of borrowings under the Credit Facility should approximate the fair market
value of such debt. Changes in interest rates, however, will change the cost of
borrowing. Assuming $75.1 million remains borrowed under the Credit Agreement,
we estimate our annual interest expense will change by $0.75 million for each
100 basis point change in the applicable interest rates utilized under the
Credit Agreement.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter into derivative contracts to hedge the price risks
associated with a portion of anticipated future oil and natural gas production.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at or
prior to expiration or exchanged for physical delivery contracts. Meridian does
not obtain collateral to support the agreements, but monitors the financial
viability of counter-parties and believes its credit risk is minimal on these
transactions. In the event of nonperformance, the Company would be exposed to
price risk. Meridian has some risk of accounting loss since the price received
for the product at the actual physical delivery point may differ from the
prevailing price at the delivery point required for settlement of the hedging
transaction.
We have entered into certain derivative contracts as summarized in the table
below. The Notional Amount is equal to the total net volumetric hedge position
of the Company during the periods presented. The positions effectively hedge
approximately 26% of our proved developed natural gas production and 28% of our
proved developed oil production during the respective terms of these agreements.
The fair values of the hedges are based on the difference between the strike
price and the New York Mercantile Exchange future prices for the applicable
trading months.
Swap / Floor Ceiling Fair Value
Notional Price Price Sept 30, 2005
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ --------------
NATURAL GAS (MMBTU)
Oct 2005 Swap 350,000 $ 6.34 N/A $ (2,646)
Oct 2005 Collar 350,000 $ 6.50 $ 7.90 (2,102)
Nov 2005 - Mar 2006 Collar 2,980,000 $ 7.50 $ 11.25 (10,381)
Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $ 14.50 (47)
---------
Total Natural Gas (15,176)
---------
CRUDE OIL (BBLS)
Oct 2005 - Jul 2006 Collar 173,000 $ 37.50 $ 47.50 (3,356)
Oct 2005 - Jul 2006 Collar 33,000 $ 40.00 $ 50.00 (571)
Aug 2006 - Jul 2007 Collar 168,000 $ 50.00 $ 74.00 (521)
---------
Total Crude Oil (4,448)
---------
$ (19,624)
=========
29
ITEM 4.
CONTROLS AND PROCEDURES
We conducted an evaluation under the supervision and with the participation of
Meridian's management, including our Chief Executive Officer and Chief
Accounting Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-15(e) under the
Securities Exchange Act of 1934) as of the end of the third quarter of 2005.
Based upon that evaluation, our Chief Executive Officer and Chief Accounting
Officer concluded that the design and operation of our disclosure controls and
procedures are effective. There have been no significant changes in our internal
controls or in other factors during the third quarter of 2005 that could
significantly affect these controls.
30
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 September 30, 2005.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning the Weeks
Island, Gibson, Bayou Pigeon, West Lake Verret and White Castle Fields. The
lawsuits seek injunctive relief and other relief, including unspecified amounts
in both actual and punitive damages for alleged breaches of mineral leases and
alleged failure to restore the plaintiffs' lands from alleged contamination and
otherwise from the defendants' oil and gas operations. The Company has not
provided any amount for these matters in its financial statements at September
30, 2005.
LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal
proceedings which exceed our insurance limits to which Meridian or any of its
subsidiaries is a party or to which any of its property is subject, other than
ordinary and routine litigation incidental to the business of producing and
exploring for crude oil and natural gas.
ITEM 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: November 8, 2005 By: /s/ LLOYD V. DELANO
-----------------------------
Lloyd V. DeLano
Senior Vice President
Chief Accounting Officer
32
EXHIBITS INDEX TO EXHIBITS
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2 Certification of President pursuant to Rule 13a-14(a) or Rule 15d-14(a)
under the Securities Exchange Act of 1934, as amended.
31.3 Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended,
and 18 U.S.C. Section 1350.
32.2 Certification of President pursuant to Rule 13a-14(b) or Rule 15d-14(b)
under the Securities Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350.
32.3 Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended,
and 18 U.S.C. Section 1350.