e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the quarterly period ended: March 31, 2008
OR
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o |
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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)
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Texas
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76-0319553 |
(State or other jurisdiction of
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(I.R.S. Employer Identification No.) |
incorporation or organization) |
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1401 Enclave Parkway, Suite 300, Houston, Texas 77077
(Address of principal executive offices) (Zip Code)
Registrants 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 þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company.
See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Number of shares of common stock outstanding at May 1, 2008: 89,363,795
Page 1 of 36
THE MERIDIAN RESOURCE CORPORATION
Quarterly Report on Form 10-Q
INDEX
2
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands of dollars, except per share information)
(unaudited)
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Three Months Ended March 31, |
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2008 |
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2007 |
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REVENUES: |
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Oil and natural gas |
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$ |
38,448 |
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$ |
40,143 |
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Price risk management activities |
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(34 |
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12 |
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Interest and other |
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127 |
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424 |
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38,541 |
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40,579 |
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OPERATING COSTS AND EXPENSES: |
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Oil and natural gas operating |
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6,070 |
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7,767 |
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Severance and ad valorem taxes |
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2,578 |
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2,844 |
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Depletion and depreciation |
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17,742 |
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21,003 |
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General and administrative |
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4,075 |
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3,895 |
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Accretion expense |
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567 |
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553 |
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31,032 |
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36,062 |
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EARNINGS BEFORE OTHER EXPENSES & INCOME TAXES |
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7,509 |
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4,517 |
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OTHER EXPENSE: |
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Interest expense |
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1,151 |
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1,539 |
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EARNINGS BEFORE INCOME TAXES |
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6,358 |
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2,978 |
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INCOME TAXES: |
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Current |
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107 |
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138 |
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Deferred |
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2,688 |
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1,172 |
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2,795 |
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1,310 |
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NET EARNINGS |
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$ |
3,563 |
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$ |
1,668 |
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NET EARNINGS PER SHARE: |
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Basic |
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$ |
0.04 |
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$ |
0.02 |
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Diluted |
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$ |
0.04 |
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$ |
0.02 |
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WEIGHTED AVERAGE NUMBER OF COMMON SHARES: |
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Basic |
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89,356 |
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89,253 |
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Diluted |
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95,302 |
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94,678 |
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See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
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March 31, |
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December 31, |
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2008 |
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2007 |
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(unaudited) |
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
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$ |
9,387 |
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$ |
13,526 |
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Restricted cash |
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31 |
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30 |
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Accounts receivable, less allowance for doubtful accounts of
$210 [2008 and 2007] |
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21,447 |
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19,874 |
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Due from affiliates |
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1,023 |
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2,580 |
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Prepaid expenses and other |
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1,929 |
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4,538 |
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Assets from price risk management activities |
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702 |
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2,453 |
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Deferred tax asset |
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1,935 |
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164 |
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Total current assets |
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36,454 |
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43,165 |
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PROPERTY AND EQUIPMENT: |
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Oil and natural gas properties, full cost method (including
$51,935 [2008] and $53,645 [2007] not subject to depletion) |
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1,794,054 |
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1,771,768 |
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Land |
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48 |
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48 |
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Equipment and other |
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20,684 |
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18,503 |
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1,814,786 |
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1,790,319 |
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Less accumulated depletion and depreciation |
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1,368,319 |
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1,350,577 |
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Total property and equipment, net |
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446,467 |
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439,742 |
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OTHER ASSETS: |
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Assets from price risk management activities |
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958 |
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865 |
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Other |
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687 |
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3 |
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Total other assets |
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1,645 |
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868 |
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TOTAL ASSETS |
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$ |
484,566 |
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$ |
483,775 |
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See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
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March 31, |
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December 31, |
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2008 |
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2007 |
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(unaudited) |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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CURRENT LIABILITIES: |
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Accounts payable |
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$ |
9,203 |
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$ |
9,583 |
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Advances from non-operators |
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1,563 |
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6,996 |
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Revenues and royalties payable |
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6,733 |
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6,592 |
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Notes payable |
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215 |
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2,662 |
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Accrued liabilities |
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15,311 |
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22,011 |
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Liabilities from price risk management activities |
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6,063 |
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2,772 |
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Asset retirement obligations |
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4,236 |
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3,365 |
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Deferred income taxes payable |
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Current income taxes payable |
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160 |
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147 |
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Total current liabilities |
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43,484 |
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54,128 |
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LONG-TERM DEBT |
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85,000 |
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75,000 |
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OTHER: |
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Deferred income taxes |
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10,704 |
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8,238 |
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Liabilities from price risk management activities |
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1,641 |
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|
861 |
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Asset retirement obligations |
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17,833 |
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20,118 |
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30,178 |
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29,217 |
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COMMITMENTS AND CONTINGENCIES (Note 7) |
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STOCKHOLDERS EQUITY: |
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Common stock, $0.01 par value (200,000,000 shares authorized,
89,450,466 [2008 and 2007] issued) |
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939 |
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|
936 |
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Additional paid-in capital |
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537,622 |
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537,145 |
|
Accumulated deficit |
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(208,579 |
) |
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(212,142 |
) |
Accumulated other comprehensive loss |
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(3,923 |
) |
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(221 |
) |
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326,059 |
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325,718 |
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Less treasury stock, at cost 86,671 [2008] and 158,683
[2007]shares |
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155 |
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288 |
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Total stockholders equity |
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325,904 |
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325,430 |
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TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
|
$ |
484,566 |
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|
$ |
483,775 |
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|
|
|
|
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|
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
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Three Months Ended March 31, |
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2008 |
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2007 |
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CASH FLOWS FROM OPERATING ACTIVITIES: |
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Net earnings |
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$ |
3,563 |
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$ |
1,668 |
|
Adjustments to reconcile net earnings to net cash
provided by operating activities: |
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|
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Depletion and depreciation |
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17,742 |
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21,003 |
|
Amortization of other assets |
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20 |
|
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|
111 |
|
Non-cash compensation |
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|
613 |
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|
644 |
|
Non-cash price risk management activities |
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34 |
|
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|
(12 |
) |
Accretion expense |
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|
567 |
|
|
|
553 |
|
Deferred income taxes |
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|
2,688 |
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|
1,172 |
|
Changes in assets and liabilities: |
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Restricted cash |
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(1 |
) |
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|
1,255 |
|
Accounts receivable |
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|
(1,573 |
) |
|
|
(1,245 |
) |
Prepaid expenses and other |
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|
2,609 |
|
|
|
2,057 |
|
Due from affiliates |
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|
1,557 |
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|
(385 |
) |
Accounts payable |
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(442 |
) |
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|
(266 |
) |
Advances from non-operators |
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(5,433 |
) |
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(2,597 |
) |
Revenues and royalties payable |
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141 |
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(849 |
) |
Asset retirement obligations |
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(269 |
) |
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(642 |
) |
Other assets and liabilities |
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950 |
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(313 |
) |
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Net cash provided by operating activities |
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22,766 |
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|
22,154 |
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CASH FLOWS FROM INVESTING ACTIVITIES: |
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Additions to property and equipment |
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(38,317 |
) |
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(33,640 |
) |
Proceeds from sale of property |
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4,562 |
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2,530 |
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Net cash used in investing activities |
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(33,755 |
) |
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(31,110 |
) |
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CASH FLOWS FROM FINANCING ACTIVITIES: |
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Proceeds from long-term debt |
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10,000 |
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Reductions in notes payable |
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(2,447 |
) |
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|
(2,475 |
) |
Repurchase of common stock |
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(352 |
) |
Additions to deferred loan costs |
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(703 |
) |
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|
|
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Net cash provided by (used in) financing activities |
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6,850 |
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(2,827 |
) |
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NET CHANGE IN CASH AND CASH EQUIVALENTS |
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(4,139 |
) |
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(11,783 |
) |
Cash and cash equivalents at beginning of period |
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13,526 |
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|
31,424 |
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CASH AND CASH EQUIVALENTS AT END OF PERIOD |
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$ |
9,387 |
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$ |
19,641 |
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
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|
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Increase (decrease) of Non-cash Activities: |
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|
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|
|
|
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Issuance of shares as compensation |
|
$ |
|
|
|
$ |
85 |
|
Issuance of shares for contract services |
|
$ |
|
|
|
$ |
642 |
|
Accrual of capital expenditures |
|
$ |
(7,577 |
) |
|
$ |
(3,072 |
) |
ARO liability new wells drilled |
|
$ |
17 |
|
|
$ |
|
|
ARO liability changes in estimates |
|
$ |
(1,729 |
) |
|
$ |
(111 |
) |
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Three Months Ended March 31, 2008 and 2007
(in thousands)
(unaudited)
|
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|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
Accumulated |
|
|
Other |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Earnings |
|
|
Comprehensive |
|
|
Treasury Stock |
|
|
|
|
|
|
Shares |
|
|
Par Value |
|
|
Capital |
|
|
(Deficit) |
|
|
Income (Loss) |
|
|
Shares |
|
|
Cost |
|
|
Total |
|
Balance, December 31, 2006 |
|
|
89,140 |
|
|
$ |
928 |
|
|
$ |
534,441 |
|
|
$ |
(219,279 |
) |
|
$ |
4,707 |
|
|
|
|
|
|
$ |
|
|
|
$ |
320,797 |
|
Issuance of rights to common stock |
|
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
Companys 401(k) plan contributions |
|
|
42 |
|
|
|
|
|
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132 |
|
Shares repurchased |
|
|
(150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150 |
|
|
|
(352 |
) |
|
|
(352 |
) |
Stock-based compensation FAS123R |
|
|
|
|
|
|
|
|
|
|
87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
425 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425 |
|
Accum. other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,134 |
) |
|
|
|
|
|
|
|
|
|
|
(4,134 |
) |
Issuance of shares for contract
services |
|
|
237 |
|
|
|
2 |
|
|
|
640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
642 |
|
Issuance of shares as compensation |
|
|
31 |
|
|
|
|
|
|
|
85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2007 |
|
|
89,300 |
|
|
$ |
932 |
|
|
$ |
535,808 |
|
|
$ |
(217,611 |
) |
|
$ |
573 |
|
|
|
150 |
|
|
$ |
(352 |
) |
|
$ |
319,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007 |
|
|
89,450 |
|
|
$ |
936 |
|
|
$ |
537,145 |
|
|
$ |
(212,142 |
) |
|
$ |
(221 |
) |
|
|
159 |
|
|
$ |
(288 |
) |
|
$ |
325,430 |
|
Issuance of rights to common stock |
|
|
|
|
|
|
3 |
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 401(k) plan contributions |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
(72 |
) |
|
|
133 |
|
|
|
130 |
|
Stock-based compensation FAS123R |
|
|
|
|
|
|
|
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
443 |
|
Accum. other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,702 |
) |
|
|
|
|
|
|
|
|
|
|
(3,702 |
) |
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2008 |
|
|
89,450 |
|
|
$ |
939 |
|
|
$ |
537,622 |
|
|
$ |
(208,579 |
) |
|
$ |
(3,923 |
) |
|
|
87 |
|
|
$ |
(155 |
) |
|
$ |
325,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
7
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(thousands of dollars)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
Net earnings |
|
$ |
3,563 |
|
|
$ |
1,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax, for
unrealized gains (losses) from hedging activities: |
|
|
|
|
|
|
|
|
Unrealized holding losses arising during period (1) |
|
|
(4,094 |
) |
|
|
(2,931 |
) |
Reclassification adjustments on settlement of contracts (2) |
|
|
392 |
|
|
|
(1,203 |
) |
|
|
|
|
|
|
|
|
|
|
(3,702 |
) |
|
|
(4,134 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss |
|
$ |
(139 |
) |
|
$ |
(2,466 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Net income tax (expense) benefit |
|
$ |
2,204 |
|
|
$ |
1,579 |
|
(2) Net income tax (expense) benefit |
|
$ |
(211 |
) |
|
$ |
648 |
|
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 Companys Annual Report on Form
10-K for the year ended December 31, 2007, as filed with the Securities and Exchange Commission
(SEC).
The financial statements included herein as of March 31, 2008, and for the three month periods
ended March 31, 2008 and 2007, 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 financial 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. SIGNIFICANT ACCOUNTING POLICIES
Drilling Rig
TMR Drilling Corporation (TMRD), a wholly owned subsidiary of the Company, owns a rig which is
used primarily to drill wells operated by the Company. In April 2008, an unaffiliated service
company, Orion Drilling, Ltd, began leasing the rig from TMRD, and operating it under a dayrate
contract with the Company. The Company records drilling expenditures under the dayrate contract as
capitalized exploration costs. All TMRD profits or losses related to lease of the rig, including
any incidental profits related to the share of drilling costs borne by our joint interest partners,
are offset against the full cost pool. SEC guidelines for full cost accounting require this method
in cases where services are performed by a company on properties that it owns and/or manages.
In the future the rig may be used by the service company for work on third party wells in which the
Company has no economic or management interest. In that case, a proportional amount of TMRDs
profit or loss related to the lease of the rig will be reflected in the statement of operations.
Recent Accounting Pronouncements
On February 15, 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities Including an Amendment of FASB Statement No. 115 (SFAS No. 159). The
statement permits entities to choose to measure eligible financial instruments and certain other
items at fair market value, with the objective of improving financial reporting by giving entities
the opportunity to mitigate volatility in reported earnings caused by measuring related assets and
liabilities differently without having to apply complex hedge accounting provisions. The Company
adopted SFAS 159 on January 1, 2008 and did not elect to apply the fair value method to any
eligible assets or liabilities at that time, see Footnote 3 elsewhere in this report.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157). SFAS 157
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosure about fair value measurements. The standard applies
prospectively to new fair value measurements performed after the required effective dates, which
are as follows: on January 1,
9
2008, for the
Company, the standard became applicable to measurements of the fair values of financial instruments
and recurring fair value measurements of non-financial assets and liabilities; on January 1, 2009,
for the Company, the standard will apply to all remaining fair value measurements, including
non-recurring measurements of non-financial assets and liabilities, such as asset retirement
obligations and impairments of long-lived assets. The Company adopted the effective portion of SFAS
157 on January 1, 2008; the adoption had no material impact on our financial position or results of
operations.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (SFAS 141(R)). SFAS
141(R) replaces SFAS No. 141, Business Combinations. SFAS 141(R) retains the purchase method of
accounting for acquisitions, but requires a number of changes, including changes in the way assets
and liabilities are recognized in purchase accounting. It also changes the recognition of assets
acquired and liabilities assumed arising from contingencies and requires the expensing of
acquisition-related costs as incurred. Generally, SFAS 141(R) will be effective for the Company on
a prospective basis for all business combinations for which the acquisition date is on or after
January 1, 2009. We do not expect the adoption of SFAS 141(R) to have a material impact on our
financial position or results of operations, provided we do not undertake a significant acquisition
or business combination.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities, which amends FASB Statement No. 133 (SFAS 161). SFAS 161 provides guidance for
additional disclosures regarding derivative contracts, including expanded discussions of risk and
hedging strategy, as well as new tabular presentations of accounting data related to derivative
instruments. SFAS 161 will be effective for fiscal years and interim periods beginning after
November 15, 2008 with early application encouraged. We do not expect the adoption of SFAS 161 to
have a material impact on our reported statements of financial position or results of operations.
3. FAIR VALUE MEASUREMENT
The Company adopted the provisions of SFAS 157, effective January 1, 2008. SFAS 157 does not
expand the use of fair value measurements, but rather, provides a framework for consistent
measurement of fair value for those assets and liabilities already measured at fair value under
other accounting pronouncements. Certain specific fair value measurements, such as those related
to share-based compensation, are not included in the scope of SFAS 157. Primarily, SFAS 157 is
applicable to assets and liabilities related to financial instruments, to some long-term
investments and liabilities, to initial valuations of assets and liabilities acquired in a business
combination, and to long-lived assets carried at fair value subsequent to an impairment write-down.
It does not apply to oil and natural gas properties accounted for under the full cost method,
which are subject to impairment based on SEC rules. SFAS 157 applies to assets and liabilities
carried at fair value on the consolidated balance sheet, as well as to supplemental fair value
information about financial instruments not carried at fair value, which the Company provides
annually under the provisions of SFAS 107, Disclosures about Fair Value of Financial Instruments.
Certain provisions of SFAS 157 have been deferred by the FASB. Accordingly, the Company has not
applied the provisions of SFAS 157 to those non-financial assets and liabilities which are measured
at fair value on a non-recurring basis. This includes asset retirement obligations, and any assets
other than oil and natural gas properties, for which an impairment write-down is recorded during
the period. There have been no such asset impairments in the current period.
The Company has applied the provisions of SFAS 157 to assets and liabilities measured at fair value
on a recurring basis. This includes oil and natural gas derivatives contracts.
10
SFAS 157 provides a definition of fair value and a framework for measuring fair value, as well as
expanding disclosures regarding fair value measurements. The framework requires fair value
measurement techniques to include all significant assumptions that would be made by willing
participants in a market transaction. These assumptions include certain factors not consistently
provided for previously by those companies utilizing fair value measurement; examples of such
factors would include the companys own credit standing (when valuing liabilities) and the buyers
risk premium. In adopting SFAS 157, the Company determined that the impact of these additional
assumptions on fair value measurements did not have a material effect on financial position or
results of operations. The Company is still assessing the potential impact of implementation in
2009 of those portions of the guidance for which the effective date has been deferred by the FASB.
SFAS 157 provides a hierarchy of fair value measurements, based on the inputs to the fair value
estimation process. It requires disclosure of fair values classified according to the levels
described below. The hierarchy is based on the reliability of the inputs used in estimating fair
value. The framework for fair value measurement assumes that transparent observable (Level 1)
inputs generally provide the most reliable evidence of fair value and should be used to measure
fair value whenever available. The classification of a fair value measurement is determined based
on the lowest level (with Level 3 as lowest) of significant input to the fair value estimation
process.
|
|
|
Level 1 fair values are based on observable inputs. Observable inputs are quoted active
market prices for assets and liabilities identical to those being valued. |
|
|
|
|
Level 2 fair values are based on observable inputs for similar assets and liabilities to
those being valued. Level 2 fair values often rely on valuation models for which the
significant inputs are observable Level 1 inputs, or inputs which can be derived from Level
1 inputs through correlation. |
|
|
|
|
Level 3 fair values are based on at least one significant unobservable input, and may
also utilize observable inputs. Unobservable inputs must be utilized when the asset or
liability being valued is not actively traded. Level 3 fair values rely on valuation
models that may utilize company-specific information or other unobservable inputs,
developed based on the best information available in the circumstances. |
The Company utilizes the modified Black-Scholes option pricing model to estimate the fair value of
oil and natural gas derivative contracts. Inputs to this model include observable inputs from the
New York Mercantile Exchange (NYMEX) for futures contracts, and inputs derived from NYMEX
observable inputs, such as implied volatility of oil and gas prices. The Company has classified
the fair values of all its derivative contracts as Level 2.
11
Assets and liabilities measured at fair value on a recurring basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2008 |
|
|
|
|
|
|
Using |
|
|
|
|
|
|
Quoted |
|
|
|
|
|
|
|
|
|
|
Prices in |
|
|
|
|
|
|
|
|
|
|
Active |
|
Significant |
|
Significant |
|
|
|
|
|
|
Markets for |
|
Other |
|
Other |
|
|
|
|
|
|
Identical |
|
Observable |
|
Unobservable |
|
|
March |
|
Assets |
|
Inputs |
|
Inputs |
Description |
|
31, 2008 |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
Assets from price
risk management
activities (1) |
|
|
1,660 |
|
|
|
|
|
|
|
1,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities from
price risk
management
activities (1) |
|
|
7,704 |
|
|
|
|
|
|
|
7,704 |
|
|
|
|
|
|
|
|
(1) |
|
Assets and liabilities from price risk management activities are oil and natural gas
derivative contracts, in the form of costless collars to sell oil and natural gas within specific
future time periods. These contracts are more fully described in Note 10. |
4. ACCRUED LIABILITIES
Below is the detail of accrued liabilities on the Companys balance sheets as of March 31, 2008 and
December 31, 2007 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Capital expenditures |
|
$ |
7,182 |
|
|
$ |
14,821 |
|
Operating expenses/taxes |
|
|
4,179 |
|
|
|
3,881 |
|
Compensation |
|
|
1,274 |
|
|
|
853 |
|
Interest |
|
|
339 |
|
|
|
460 |
|
Other |
|
|
2,337 |
|
|
|
1,996 |
|
|
|
|
|
|
|
|
Total |
|
$ |
15,311 |
|
|
$ |
22,011 |
|
|
|
|
|
|
|
|
5. 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. On February 21, 2008, the Company amended this Credit Facility
(Amended Credit Facility). The lending institutions under the Amended Credit Facility, include
Fortis Capital Corp. as administrative agent, co-lead arranger and bookrunner; The Bank of
12
Nova
Scotia, as co-lead arranger and syndication agent; Comerica Bank, US Bank NA and Allied Irish Bank
plc each in their respective capacities as lenders, collectively the Lenders. The current
borrowing base under the Amended Credit Facility was determined to be $110 million by the
syndication group effective April 30, 2008. The maturity date was extended to February 21, 2012.
As of March 31, 2008, outstanding borrowings under the Amended Credit Facility totaled $85 million.
The Amended 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 natural gas reserves, the
banks price assumptions and other various factors unique to each member bank. The Companys
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 Amended Credit Facility are secured by pledges of outstanding capital stock
of the Companys 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 Amended 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, limitations on the
repurchase of the Companys Common Stock and an unqualified audit report on the Companys
consolidated financial statements, with, all of which the Company is in compliance.
Under the Amended 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 agents
prime rate; or (b) federal funds-based rate plus 1/2 of 1%, plus an additional 0.75% to 1.75%
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 2.5%, depending on the ratio of the
aggregate outstanding loans and letters of credit to the borrowing base. At March 31, 2008, the
three-month LIBOR interest rate was 2.69%. The Amended Credit Facility provides for commitment
fees of 0.375% calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Amended Credit Facility.
6. INCOME TAXES
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of SFAS No. 109 (FIN 48). FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an enterprises 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.
The Company adopted the provisions of FIN 48 on January 1, 2007, and the adoption had no material
impact on the Companys results of operations and financial condition.
13
7. 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 Meridians alleged gross
negligence, willful misconduct and breach of fiduciary duty 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 Meridians satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond had been added as a defendant by Hawkins claiming Mr. Bond,
when he was General Manager of Hawkins, did not have the right to consent, could not consent or
breached his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr.
James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He
served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bonds
employment with Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian
Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond
was also the father-in-law of Michael J. Mayell, the President of the Company. Management continues
to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent,
Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridians actions
were not grossly negligent, but were within the business judgment rule. Since Mr. Bonds death, a
pleading has recently been filed substituting the proper party for Mr. Bond. The Company is unable
to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to
estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the
Company has not provided any amount for this matter in its financial statements at March 31, 2008.
Title/lease disputes. Title and lease disputes may arise in the normal course of the Companys
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Environmental litigation. Various landowners have sued Meridian (along with numerous other oil
companies) in 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 Companys oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual
indemnity and defense from Meridian based upon the terms of the purchase and sale agreement related
to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity
and defense from Meridian on the basis of a purchase and sale agreement related to the field(s)
referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also
demanded defense and indemnity from their subsequent purchasers of the fields. The Company is
unable to express an opinion with respect to the likelihood of an unfavorable outcome of these
matters or to estimate the amount or range of potential loss should any outcome be unfavorable.
Therefore, the Company has not provided any amount for these matters in its financial statements at
March 31, 2008.
Consent Decree. During the fourth quarter of 2007 the Company entered into a Consent Decree with
the United States Environmental Protection Agency (EPA) in settlement of alleged violations of
the Clean Water Act, as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the
Company paid $504,000 in civil penalties for alleged discharges of crude oil into navigable waters
or adjoining shorelines from the Companys operations at the Weeks Island field in Iberia Parish,
Louisiana. The Company will also be subject to certain injunctive relief, requiring the Company to
enhance certain pipeline survey, monitoring and reporting activities. Under the Consent Decree,
the Company does not admit any liability arising out of the occurrences described in the Consent
Decree or the related Complaint. In 2007, the Company recorded an expense for the above amount in
oil and natural gas operating expenses.
14
Litigation involving insurable issues. There are no material legal proceedings involving insurable
issues which exceed 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.
8. COMMON STOCK
In March 2007, the Companys Board of Directors authorized a share repurchase program. Under the
program, the Company may repurchase in the open market or through privately negotiated transactions
up to $5 million worth of common shares per year over three years. The timing, volume, and nature
of share repurchases will be at the discretion of management, depending on market conditions,
applicable securities laws, and other factors. Prior to implementing this program, the Company was
required to seek approval of the repurchase program from the Lenders under the Credit Facility. The
repurchase program was approved by the Lenders, subject to certain restrictive covenants. During
February 2007, the lenders in the Credit Facility unanimously approved an amendment increasing the
available limit for the Companys repurchase of its common stock from $1.0 million to $5.0 million
annually. The amendment contained restrictive covenants on the Companys ability to repurchase its
common stock including (i) the Company cannot utilize funds under the Credit Facility to fund any
stock repurchases and (ii) immediately prior to any repurchase, availability under the Credit
Facility must be equal to at least 20% of the then effective borrowing base. From March 2007, the
inception of the share repurchase program, the Company has repurchased 501,300 common shares at a
cost of $1,158,000, of which 414,629 shares have been reissued for 401(k) contributions, for
contract services and for compensation. The program does not require the Company to repurchase any
specific number of shares and may be modified, suspended, or terminated at any time without prior
notice. The Company expects repurchases to be funded by available cash. It is the intent of the
Company to continue this program through this and future years.
9. 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 March 31, |
|
|
|
2008 |
|
|
2007 |
|
Numerator: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
3,563 |
|
|
$ |
1,668 |
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share weighted-average shares outstanding |
|
|
89,356 |
|
|
|
89,253 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
Warrants |
|
|
5,946 |
|
|
|
5,425 |
|
Employee and director stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions |
|
|
95,302 |
|
|
|
94,678 |
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
0.04 |
|
|
$ |
0.02 |
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
0.04 |
|
|
$ |
0.02 |
|
|
|
|
|
|
|
|
15
10. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments with value fluctuations that correlate
strongly with the underlying commodity being hedged. From time to time, we 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 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 Companys 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 SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging
Activities, and any changes in fair value are recorded in accumulated 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 $34
thousand loss related to hedge ineffectiveness during the three months ended March 31, 2008, and a
gain of approximately $12 thousand during the three months ended March 31, 2007.
As of March 31, 2008, the estimated fair value of the Companys oil and natural gas contracts was
an unrealized loss of approximately $6.0 million ($3.9 million net of tax), which is recognized in
accumulated other comprehensive loss. Based upon oil and natural gas commodity prices at March
31, 2008, approximately $5.3 million of the loss deferred in accumulated other comprehensive loss
could potentially decrease gross revenues over the next twelve months. These derivative agreements
expire at various dates through December 31, 2009.
All of the Companys current hedging contracts are in the form of costless collars. The costless
collars provide the Company with a lower limit floor price and an upper limit ceiling price on
the hedged volumes. The floor price represents the lowest price the Company will receive for the
hedged volumes while the ceiling price represents the highest price the Company will receive for
hedged volumes. The costless collars are settled monthly based on the NYMEX futures contract.
Net settlements under these contracts increased (decreased) oil and natural gas revenues by
($603,000) and $1,850,000 for the three months ended March 31, 2008 and 2007, respectively, as a
result of hedging transactions.
The notional amount is equal to the total net volumetric hedge position of the Company during the
periods presented. As of March 31, 2008, the positions effectively hedge approximately 36% of the
estimated proved developed natural gas production and 32% of the estimated proved developed oil
production during the respective terms of the hedging agreements. The fair values of the hedges
are based on the difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
16
The fair value of the hedging agreements is recorded on the consolidated balance sheet as assets or
liabilities. The estimated fair value of the hedging agreements as of March 31, 2008, is provided
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Price |
|
|
March 31, 2008 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2008 Dec 2008 |
|
Collar |
|
|
1,530,000 |
|
|
$ |
7.00 |
|
|
$ |
12.15 |
|
|
$ |
(486 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
700,000 |
|
|
$ |
7.50 |
|
|
$ |
11.50 |
|
|
|
(279 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
1,310,000 |
|
|
$ |
7.50 |
|
|
$ |
10.10 |
|
|
|
(1,174 |
) |
Jan 2009 Dec
2009 |
|
Collar |
|
|
1,230,000 |
|
|
$ |
7.50 |
|
|
$ |
10.45 |
|
|
|
(957 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
170,000 |
|
|
$ |
8.00 |
|
|
$ |
10.50 |
|
|
|
(97 |
) |
Jan 2009 Dec
2009 |
|
Collar |
|
|
760,000 |
|
|
$ |
8.00 |
|
|
$ |
10.30 |
|
|
|
(513 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas |
|
|
|
(3,506 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2008 Dec 2008 |
|
Collar |
|
|
32,000 |
|
|
$ |
55.00 |
|
|
$ |
83.00 |
|
|
|
(579 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
14,000 |
|
|
$ |
65.00 |
|
|
$ |
80.60 |
|
|
|
(278 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
27,000 |
|
|
$ |
65.00 |
|
|
$ |
85.00 |
|
|
|
(444 |
) |
April 2008 |
|
Collar |
|
|
6,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(117 |
) |
May 2008 Jul
2008 |
|
Collar |
|
|
15,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(291 |
) |
Apr 2008 Jul
2008 |
|
Collar |
|
|
16,000 |
|
|
$ |
65.00 |
|
|
$ |
93.15 |
|
|
|
(171 |
) |
Apr 2008 Jul
2008 |
|
Collar |
|
|
12,000 |
|
|
$ |
70.00 |
|
|
$ |
87.40 |
|
|
|
(178 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
14,000 |
|
|
$ |
75.00 |
|
|
$ |
102.50 |
|
|
|
(82 |
) |
Jan 2009 Dec
2009 |
|
Collar |
|
|
23,000 |
|
|
$ |
70.00 |
|
|
$ |
93.55 |
|
|
|
(238 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
57,000 |
|
|
$ |
85.00 |
|
|
$ |
111.40 |
|
|
|
(80 |
) |
Jan 2009 Dec 2009 |
|
Collar |
|
|
43,000 |
|
|
$ |
80.00 |
|
|
$ |
111.00 |
|
|
|
(80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil |
|
|
|
(2,538 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(6,044 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Note 13, Subsequent Events, for additional information.
11. SHARE-BASED COMPENSATION
Stock Options
The Company records share-based compensation expense under the provisions of SFAS No. 123R,
Share-Based Payment. Compensation expense is based on the fair value of the share-based award
determined at grant date and recognized over the service period, which is generally the vesting
period of the award. Share-based compensation expense of approximately $40,000 was recorded in the
three months ended March 31, 2008 and $87,000 was recognized in the three month period ended March
31, 2007.
12. ASSET RETIREMENT OBLIGATIONS
The Company follows SFAS No. 143, Accounting for Asset Retirement Obligations, which 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
17
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 Companys 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. The Company records gains or losses
from settlements as an adjustment to the full cost pool. 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 Companys asset retirement obligations for the
three months ended March 31, 2008, and for the year ended December 31, 2007 (thousands of dollars):
|
|
|
|
|
Asset retirement obligation at December 31, 2006 |
|
$ |
22,808 |
|
|
Additional retirement obligations recorded in 2007 |
|
|
476 |
|
Settlements during 2007 |
|
|
(2,055 |
) |
Revisions to estimates and other changes during 2007 |
|
|
24 |
|
Accretion expense for 2007 |
|
|
2,230 |
|
|
|
|
|
Asset retirement obligation at December 31, 2007 |
|
|
23,483 |
|
|
Additional retirement obligations recorded in 2008 |
|
|
17 |
|
Settlements during 2008 |
|
|
(269 |
) |
Revisions to estimates and other changes during 2008 |
|
|
(1,729 |
) |
Accretion expense for 2008 |
|
|
567 |
|
|
|
|
|
Asset retirement obligation at March 31, 2008 |
|
$ |
22,069 |
|
|
|
|
|
The Companys revisions to estimates represent changes to the expected amount and timing of
payments to settle the asset retirement obligations. These changes primarily result from obtaining
new information about the timing of our obligations to plug the natural gas and oil wells and costs
to do so.
13. SUBSEQUENT EVENTS
During April 2008, the Company entered into a series of hedging contracts to hedge a portion of its
oil and natural gas production for 2009. The hedge contracts were completed in the form of
costless collars. The costless collars provide the Company with a lower limit floor price and an
upper limit ceiling price on the hedged volumes. The floor price represents the lowest price the
Company will receive for the hedged volumes, while the ceiling price represents the highest price
the Company will receive for the hedged volumes. The costless collars will be settled monthly based
on the NYMEX futures contract of oil and natural gas during each respective month. The Notional
Amount is equal to the total net volumetric hedge position of the Company during the periods
presented. These hedge contracts, combined with those discussed in Note 10, effectively hedge
approximately 39% of the estimated proved developed natural gas production, and 38% of the
estimated proved developed oil production during the respective terms of the hedging agreements.
The following table summarizes the contracted volumes and prices for the new hedge contracts
completed in April 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
Floor Price |
|
Ceiling Price |
|
|
Amount |
|
($ per unit) |
|
($ per unit) |
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2009 Dec 2009
|
|
|
540,000 |
|
|
$ |
8.00 |
|
|
$ |
13.35 |
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
Jan 2009 Dec 2009
|
|
|
49,000 |
|
|
$ |
85.00 |
|
|
$ |
128.50 |
|
18
In April 2008 the Company made significant changes in the structure of the compensation of our top
two executives, Messrs. Reeves and Mayell, our CEO and COO. Effective April 29, 2008, the
employment contracts for Messrs. Reeves and Mayell were terminated and replaced with new
agreements. In addition, certain other agreements that governed other elements of their
compensation packages were also terminated. Messrs. Reeves and Mayell agreed to these changes under
the terms of the termination agreements executed by each of them effective April 29, 2008. The
termination agreements provide the following: termination payments totaling approximately $4.9
million to each of Messrs. Reeves and Mayell, for a total of $9.9 million to the Company, which
expense will be recognized in the second quarter of 2008; additional tax gross-up payment to each
of Messrs. Reeves and Mayell to be determined at a later date; reimbursement for their personal
legal expenses related to negotiation of the termination agreements and new employment contracts
totaling not more than $100,000 for the two officers combined.
In addition, the Company terminated the deferred compensation plan provided to these officers.
Termination of the plan will result in issuance of a total of 2,873,354 shares of new common stock
to Messrs. Reeves and Mayell (combined) during the second quarter of 2008; an additional 821,784
shares will be issued to each of these two officers six months after the officer leaves the
employment of the Company. Substantially all of the compensation expense related to these shares
was recognized historically, when the rights to such future shares were granted; the rights have
also been consistently included in Company computations of diluted earnings per share. Termination
of the plan requires conversion of the rights into shares of common stock.
On May 2, 2008, the Company, through its wholly owned subsidiary TMRD, entered into a financing
agreement with The CIT Group Equipment Financing, Inc. (CIT). Under the terms of the agreement,
TMRD borrowed $10.0 million, at a fixed interest rate of 6.625% in order to refinance the purchase
of a land-based drilling rig to be used in Company operations. The rig was recently purchased
using funds available to the Company under the Amended Credit Facility. Funds from the new
agreement were used to reduce borrowing under the Amended Credit Facility. The new loan is
collateralized by the drilling rig, as well as general corporate credit. The term of the loan is
five years; monthly payments of $196,248 for interest and principal are to be made until the loan
is completely repaid at termination of the agreement on May 2, 2013.
ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
General.
The Companys business plan has been modified to extend and expand its exploration portfolio
beyond its conventional assets in the Louisiana and Texas Gulf Coast regions to include the
establishment of large acreage positions in known unconventional and resource plays located within
producing regions of the lower continental United States containing longer-lived reserves.
Management modified its business strategy while retaining its position in the Gulf Coast region of
south Louisiana and Texas and has directed cash flow from operations generated from increased
energy prices to acquisition of large exploratory acreage positions, with the objective of finding
properties with multiple repeatable wells and longer-lived reserves.
Operations Update
Louisiana
The Weeks Island and Turtle Bayou fields continue to render additional opportunities from new well
locations, sidetracks and development drilling. Recent activity in these fields has served to
extend field pay and add new
reserves and rate. In these prolific fields, the Company has identified several additional well
locations, recompletions and workovers, that it expects could significantly add rate and reserves
during 2008.
19
During the first quarter, the Company drilled a sidetrack well to test multiple sands under the
salt overhang in its Myles Salt No. 27 well. The well was drilled to approximately 11,400 feet,
measured depth (MD). Logs from the well indicated approximately 132 feet of pay in the M, O, P
and Q sands, extending field pay and adding new reserves and rate. The well was tested and is
currently producing from the Q sand at a gross daily flow rate of 2.1 Mmcfe/d (1.1 Mmcfe/d, net).
Flowing tubing pressure was measured at approximately 2,600 psi through an 8/64th inch
choke. In this prolific oil producing field, the Company has identified several additional well
locations, recompletions and workovers that will serve to enhance reserves and production during
2008.
Coming up in the short term at Weeks Island, the Company will be reentering the Goodrich-Cocke No.
6 ST well. The well will be sidetracked at approximately 4,700 feet and drilled an additional 3,600
feet, testing the F-sand in the Miocene formation at a depth of approximately 8,300 feet.
In the Ramos field area, the Company recompleted the Avoca 8-1 well to the Big Hum 2 formation
which tested at a daily flow rate of 2.6 Mmcfe/d (1.8 Mmcfe/d, net). Flowing tubing pressure was
measured at approximately 4,000 psi through a 10/64ths-inch choke. The Company owns approximately
92% working interest in the well.
Additionally, the Company is also reprocessing its 3-D seismic data over Weeks Island and other
regions in its South Louisiana play area (Atchafalaya Bay and Barataria Bay), the expectations
being that the reprocessed and newly acquired 3-D data will enhance the Companys ability to
generate low-to-moderate risk new projects in this core area where it is already active and has
operations and infrastructure in place. It is anticipated that the greatest near term and long term
impact on production and reserve value will result from the Companys capital spending program in
these two areas this year.
In the Biloxi Marshland area, the natural gas transmission company that takes natural gas from the
Companys two production facilities in that area has temporarily shut-in production from the
various wells that feed into those facilities. Maintenance and repairs are being conducted on the
transmission companys line to correct minor damage caused by the hurricanes of 2005. The wells
were shut-in on April 25, 2008, and Meridian is being informed by the pipeline operator that
repairs should be completed by May 12, 2008. The amount of production being shut-in is estimated to
be 7.6 Mmcfe/d net. After the completion of these repairs, daily production rates for the Company
are projected to be around 45 Mmcfe/d.
Texas Austin Chalk
In the East Texas area, initial production test on the Freeman No. 1 well, located in Polk County,
Texas resulted in gross daily flow rates as high as 16.7 Mmcfe/d (8.8 Mmcfe/d, net). The gross
amount includes 336 Bopd. The well was drilled vertically to approximately 13,000 feet, then added
two horizontal laterals, 4,000 feet and 5,600 feet respectively. The Company expects that the well
(which was recently tested) will display similar producing characteristics to other Austin Chalk
wells in the area, with the typical hyperbolic decline curve from these production levels, during
the coming months. The well is currently producing at an average rate of 2.1 Mmcfe/d (1.1 Mmcfe/d,
net). Meridian owns approximately 69% working interest in this well.
Initial production test results on the Black Stone Minerals(BSM) No. 5 well, located in Polk
County, Texas in the Companys East Texas Austin Chalk Play resulted in gross daily flow rates as
high as 18.1 Mmcfe/d (8.8 Mmcfe/d, net). The gross amount includes 960 Bopd. The well was drilled
vertically to approximately 13,000 feet, then added two horizontal laterals, each approximating
5,500 feet. 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 these
production levels, during the coming months. Meridian owns approximately 65%
working interest in this well.
20
The Company continues the extension of its East Texas Austin Chalk play with a two rig program. The
Davis A-388 well is located approximately four miles north of the BSM No. 5 well and is currently
drilling the vertical section at a depth of approximately 12,300 feet. The Company has
approximately 45% working interest in this dual horizontal lateral well. Additionally, the dual
lateral BSM 507 No. 1 well has recently spud and is currently drilling at 2,500 feet.
As part of the Companys business plan, it has acquired a significant lease position (approximately
30,000 acres) in South Texas within a major Austin Chalk play in the region that covers over
200,000 acres. The Company has scheduled a well to be drilled in late summer 2008 in this area.
Additionally, a shallow oil well is scheduled to be drilled to test the Vicksburg formation during
2008 in Bee County.
Capital Expenditure Plans for 2008
The Company anticipates a 2008 capital spending budget of approximately $74.3 million for new
prospect opportunities, ranging in depths from shallow to deep. Based on current projections, these
expenditures are within the Companys expected operating cash flows (including cash on hand) and
allow the Company the flexibility to take on additional prospects, acquisitions or joint ventures
as the opportunities are presented or developed throughout the year.
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 March 31,
2008, was $86.91 per barrel compared to $50.30 per barrel for the three months ended March 31,
2007, and $81.03 per barrel for the three months ended December 31, 2007. Our average natural gas
price (after adjustments for hedging activities) for the three months ended March 31, 2008, was
$8.55 per Mcf compared to $7.34 per Mcf for the three months ended March 31, 2007, and $7.18 per
Mcf for the three months ended December 31, 2007. 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. Refer to Item 3, Quantitative and Qualitative
Disclosures about Market Risk, for information regarding commodity price risk management activities
utilized to mitigate a portion of the near term effects of this exposure to price volatility.
Critical Accounting Policies and Estimates. The Companys 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
Companys Annual Report on Form 10-K for the year ended December 31, 2007, for further discussion.
Results of Operations
Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007
Operating Revenues. First quarter 2008 oil and natural gas revenues, which include oil and natural
gas hedging activities (see Note 10 of Notes to Consolidated Financial Statements), decreased $1.7
million (4%) as compared to first quarter 2007 revenues due to a 29% decrease in production
volumes partially offset by a
21
35% increase in average commodity prices on a natural gas equivalent
basis. Oil and natural gas production volumes totaled 3,731 Mmcfe for the first quarter of 2008
compared to 5,257 Mmcfe for the comparable period of 2007. Our average daily production decreased
from 58 Mmcfe during the first quarter of 2007 to 41 Mmcfe for the first quarter of 2008. First
quarter 2008 production was generally lower due to natural production declines.
The following table summarizes the Companys operating revenues, production volumes and average
sales prices for the three months ended March 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
March 31, |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
|
184 |
|
|
|
249 |
|
|
|
(26 |
%) |
Natural gas (MMcf) |
|
|
2,626 |
|
|
|
3,764 |
|
|
|
(30 |
%) |
Mmcfe |
|
|
3,731 |
|
|
|
5,257 |
|
|
|
(29 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
86.91 |
|
|
$ |
50.30 |
|
|
|
73 |
% |
Natural gas (per Mcf) |
|
$ |
8.55 |
|
|
$ |
7.34 |
|
|
|
16 |
% |
Mmcfe |
|
$ |
10.31 |
|
|
$ |
7.64 |
|
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues (000s): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
16,006 |
|
|
$ |
12,519 |
|
|
|
28 |
% |
Natural gas |
|
$ |
22,442 |
|
|
$ |
27,624 |
|
|
|
(19 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues |
|
$ |
38,448 |
|
|
$ |
40,143 |
|
|
|
(4 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses. Oil and natural gas operating expenses on an aggregate basis decreased $1.7
million (22%) to $6.1 million during the first quarter of 2008, compared to $7.8 million in the
first quarter of 2007. On a unit basis, lease operating expenses increased $0.15 per Mcfe to $1.63
per Mcfe for the first quarter of 2008 from $1.48 per Mcfe for the first quarter of 2007. Oil and
natural gas operating expenses decreased primarily due to decreased workovers, lower insurance
costs, sale of properties and decreased maintenance-related activities. The increase in the per
Mcfe rate was additionally attributable to the lower production between the two corresponding
periods.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes decreased $0.2 million (9%) to $2.6
million for the first quarter of 2008, compared to $2.8 million during the same period in 2007
primarily because of the decrease in production and a lower natural gas tax rate partially offset
by an increase in crude oil prices. Meridians 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 $0.269 per Mcf for natural gas, a decrease from
$0.373 per Mcf for the first quarter of 2007. On an equivalent unit of production basis, severance
and ad valorem taxes increased to $0.69 per Mcfe from $0.54 per Mcfe for the comparable three-month
period.
Depletion and Depreciation. Depletion and depreciation expense decreased $3.3 million (16%) during
the first quarter of 2008 to $17.7 million, from $21.0 million for the same period of 2007. This
was primarily the result of a decrease in oil and natural gas production. On a unit basis,
depletion and depreciation expense increased by $0.77 per Mcfe, to $4.76 per Mcfe for the three
months ended March 31, 2008, compared to $3.99 per Mcfe for the same period in 2007, primarily due
to additional capital expenditures.
22
General and Administrative Expense. General and administrative expense was $4.1 million for 2008
compared to $3.9 million for 2007. The $0.2 million increase was primarily due to legal fees and
consulting services. On an equivalent unit of production basis, general and administrative
expenses increased $0.35 per Mcfe to $1.09 per Mcfe for the first quarter of 2008 compared to $0.74
per Mcfe for the comparable 2007 period primarily due to lower production rates between the
periods.
Interest Expense. Interest expense decreased $0.4 million (25%), to $1.2 million for the first
quarter of 2008 in comparison to $1.6 million for the first quarter of 2007. The decrease is
primarily a result of lower interest rates, combined with increased capitalized interest on the
drilling rig construction partially offset by a higher debt balance.
Liquidity and Capital Resources
Working Capital. During the first quarter of 2008, Meridians capital expenditures were internally
financed with cash flow from operations, cash on hand and the drawdown on the amended credit
facility. As of March 31, 2008, the Company had a cash balance of $9.4 million and a working
capital deficit of $7.0 million.
Cash Flows. Net cash provided by operating activities was $22.8 million for the three months ended
March 31, 2008, as compared to $22.2 million for the same period in 2007. The increase of $0.6
million was primarily due to lower operating expenses and higher crude oil and natural gas
commodity prices partially offset by lower production volumes.
Net cash used in investing activities was $33.8 million during the three months ended March 31,
2008, versus $31.1 million in the first three months of 2007 due to increased capital expenditures
partially offset by higher property sales.
Cash flows provided by financing activities during the first three months of 2008 were $6.9
million, compared to cash used in financing activities of $2.8 million during the first three
months of 2007 primarily due to the drawdown on the amended credit facility of $10 million.
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.
On February 21, 2008, the Company amended this Credit Facility (Amended Credit Facility). The
lending institutions under the Amended Credit Facility, include Fortis Capital Corp. as
administrative agent, co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger
and syndication agent; Comerica Bank, US Bank NA and Allied Irish Bank plc each in their respective
capacities as lenders, collectively the Lenders. The current borrowing base under the Amended
Credit Facility was determined to be $110 million by the syndication group effective April 30,
2008. The maturity date was extended to February 21, 2012. As of March 31, 2008, outstanding
borrowings under the Amended Credit Facility totaled
$85 million.
The Amended 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 natural gas reserves, the
banks price assumptions and various other factors
23
unique to each member bank. The Companys
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 Amended Credit Facility are secured by pledges of outstanding capital stock
of the Companys 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 Amended 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, limitations on the
repurchase of the Companys Common Stock and an unqualified audit report on the Companys
consolidated financial statements, with all of which the Company is in compliance.
Under the Amended 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 agents
prime rate; or (b) federal funds-based rate plus 1/2 of 1%, plus an additional 0.75% to 1.75%
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 2.5%, depending on the ratio of the
aggregate outstanding loans and letters of credit to the borrowing base. At March 31, 2008, the
three-month LIBOR interest rate was 2.69%. The Amended Credit Facility provides for commitment
fees of 0.375% calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Amended Credit Facility.
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,
Accounting for Derivative Instruments and Certain Hedging Activities, 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.
24
Capital Expenditures. Total capital expenditures for this period were approximately $30.7 million.
Our strategy is to blend exploration drilling activities with high-confidence workover and
development projects in order to capitalize on periods of high commodity prices. Capital
expenditures were for acreage acquisitions, exploratory drilling, geological and geophysical,
workovers, and related capitalized general and administrative expenses.
The 2008 capital expenditures plan is currently forecast at approximately $74.3 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 2008 plan utilizing cash flow from operations and cash on hand.
When appropriate, excess cash flow from operations beyond that needed for the 2008 capital
expenditures plan will be used to de-lever the Company by development of exploration discoveries or
direct payment of debt.
Dividends. It is our policy to retain existing cash for reinvestment in our business, and
therefore, we do not anticipate that dividends will be paid with respect to the common stock in the
foreseeable future.
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 Managements 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,
25
compliance with government permitting
requirements, shortages of or delays in obtaining equipment, reductions in product prices,
limitations in the market for products, litigation and disputes in the ordinary course of business.
Although we maintain insurance coverage considered to be customary in the industry, we are not
fully insured against certain of these risks either because such insurance is not available or
because of high premium costs. We cannot predict if or when any such risks could affect our
operations. The occurrence of a significant event for which we are not adequately insured could
cause our actual results to differ from those reflected in our forward-looking statements.
Drilling Risks. Our decision to purchase, explore, develop or otherwise exploit a prospect or
property will depend in part on the evaluation of data obtained through geophysical and geological
analysis, production data and engineering studies, which are inherently imprecise. Therefore, we
cannot assure you that all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause the actual results
to differ from those reflected in our forward-looking statements.
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 cash flow hedge
positions, discounted at 10%, and the lower of cost or fair value of unproved properties adjusted
for related income tax effects.
The calculation of the ceiling test and the provision for depletion and amortization are based on
estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities
of proved reserves and in projecting the future rates of production, timing, and plan of
development. The accuracy of any reserves estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify a revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil and natural gas that
are ultimately recovered.
Due to the imprecision in estimating oil and natural gas revenues as well as the potential
volatility in oil and natural gas prices and their effect on the carrying value of our proved oil
and natural gas reserves, there can be no assurance that write-downs in the future will not be
required as a result of factors that may negatively affect the present value of proved oil and
natural gas reserves and the carrying value of oil and natural gas properties, including volatile
oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve
quantities and unsuccessful drilling activities. At March 31, 2008, we had a cushion (i.e. the
excess of the ceiling over our capitalized costs) of approximately $181 million (before tax).
26
Borrowing base for the Credit Facility. The Amended Credit Facility with Fortis Capital Corp. as
administrative agent, is presently scheduled for borrowing base redetermination dates on a
semi-annual basis with the next such redetermination scheduled for October 31, 2008. 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 Companys control.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
The Company is currently exposed to market risk from hedging contracts changes and changes in
interest rates. A discussion of the market risk exposure in financial instruments follows.
Interest Rates
We are subject to interest rate risk on our long-term fixed interest rate debt and variable
interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the
Amended Credit Facility. Since interest charged on borrowings under the Amended Credit Facility
floats with prevailing interest rates (except for the applicable interest period for Eurodollar
loans), the carrying value of borrowings under the Amended Credit Facility should approximate the
fair market value of such debt. Changes in interest rates, however, will change the cost of
borrowing. Assuming $85 million remains borrowed under the Amended Credit Facility, we estimate
our annual interest expense will change by $0.85 million for each 100 basis point change in the
applicable interest rates utilized under the Amended Credit Facilty.
Hedging Contracts
From time to time, Meridian addresses 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, we 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.
All of the Companys current hedging contracts are in the form of costless collars. The costless
collars provide the Company with a lower limit floor price and an upper limit ceiling price on
the hedged volumes. The floor price represents the lowest price the Company will receive for the
hedged volumes while the ceiling price represents the highest price the Company will receive for
the hedged volumes. The costless collars are settled monthly based on the NYMEX futures contract.
The notional amount is equal to the total net volumetric hedge position of the Company during the
periods presented. As of March 31, 2008, the positions effectively hedge approximately 36% of our
proved developed natural gas production and 32% of our 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 NYMEX future prices for the applicable trading months.
27
The fair values of our hedging agreements are recorded on our consolidated balance sheet as assets
or liabilities. The estimated fair value of our hedging agreements as of March 31, 2008, is
provided below (see the Companys website at www.tmrc.com for a quarterly breakdown of the
Companys hedge position for 2008 and beyond):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Price |
|
|
March 31, 2008 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2008 Dec 2008 |
|
Collar |
|
|
1,530,000 |
|
|
$ |
7.00 |
|
|
$ |
12.15 |
|
|
$ |
(486 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
700,000 |
|
|
$ |
7.50 |
|
|
$ |
11.50 |
|
|
|
(279 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
1,310,000 |
|
|
$ |
7.50 |
|
|
$ |
10.10 |
|
|
|
(1,174 |
) |
Jan 2009 Dec
2009 |
|
Collar |
|
|
1,230,000 |
|
|
$ |
7.50 |
|
|
$ |
10.45 |
|
|
|
(957 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
170,000 |
|
|
$ |
8.00 |
|
|
$ |
10.50 |
|
|
|
(97 |
) |
Jan 2009 Dec
2009 |
|
Collar |
|
|
760,000 |
|
|
$ |
8.00 |
|
|
$ |
10.30 |
|
|
|
(513 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas |
|
|
|
(3,506 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2008 Dec 2008 |
|
Collar |
|
|
32,000 |
|
|
$ |
55.00 |
|
|
$ |
83.00 |
|
|
|
(579 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
14,000 |
|
|
$ |
65.00 |
|
|
$ |
80.60 |
|
|
|
(278 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
27,000 |
|
|
$ |
65.00 |
|
|
$ |
85.00 |
|
|
|
(444 |
) |
April 2008 |
|
Collar |
|
|
6,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(117 |
) |
May 2008 Jul
2008 |
|
Collar |
|
|
15,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(291 |
) |
Apr 2008 Jul
2008 |
|
Collar |
|
|
16,000 |
|
|
$ |
65.00 |
|
|
$ |
93.15 |
|
|
|
(171 |
) |
Apr 2008 Jul
2008 |
|
Collar |
|
|
12,000 |
|
|
$ |
70.00 |
|
|
$ |
87.40 |
|
|
|
(178 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
14,000 |
|
|
$ |
75.00 |
|
|
$ |
102.50 |
|
|
|
(82 |
) |
Jan 2009 Dec
2009 |
|
Collar |
|
|
23,000 |
|
|
$ |
70.00 |
|
|
$ |
93.55 |
|
|
|
(238 |
) |
Apr 2008 Dec 2008 |
|
Collar |
|
|
57,000 |
|
|
$ |
85.00 |
|
|
$ |
111.40 |
|
|
|
(80 |
) |
Jan 2009 Dec 2009 |
|
Collar |
|
|
43,000 |
|
|
$ |
80.00 |
|
|
$ |
111.00 |
|
|
|
(80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil |
|
|
|
(2,538 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(6,044 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above excludes hedges entered into after March 31, 2008; see Note 13, Subsequent Events, of the
Notes to Consolidated Financial Statements for additional information.
ITEM 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We conducted an evaluation under the supervision of and with the participation of Meridians
management, including our Chief Executive Officer, President 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 first quarter of
2008. Based upon that evaluation, our Chief Executive Officer, President 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 first quarter of 2008 that could significantly affect these controls.
28
Changes in Internal Controls
During the three month period ended March 31, 2008, there were no changes in the Companys 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 Meridians alleged gross
negligence, willful misconduct and breach of fiduciary duty 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 Meridians satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond had been added as a defendant by Hawkins claiming Mr. Bond,
when he was General Manager of Hawkins, did not have the right to consent, could not consent or
breached his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr.
James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He
served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bonds
employment with Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian
Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond
was also the father-in-law of Michael J. Mayell, the President of the Company. Management continues
to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent,
Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridians actions
were not grossly negligent, but were within the business judgment rule. Since Mr. Bonds death, a
pleading has recently been filed substituting the proper party for Mr. Bond. The Company is unable
to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to
estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the
Company has not provided any amount for this matter in its financial statements at March 31, 2008.
Title/lease disputes. Title and lease disputes may arise in the normal course of the Companys
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Environmental litigation. Various landowners have sued Meridian (along with numerous other oil
companies) in 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 Companys oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual
indemnity and defense from Meridian based upon the terms of the purchase and sale agreement related
to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity
and defense from Meridian on the basis of a purchase and sale agreement related to the field(s)
referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also
demanded defense and indemnity from their subsequent purchasers of the fields. The Company is
unable to express an opinion with respect to the likelihood of an unfavorable outcome of these
matters or to estimate the amount or range of potential loss should any outcome be unfavorable.
Therefore, the Company has not provided any amount for these matters in its financial statements at
March 31, 2008.
29
Consent Decree. During the fourth quarter of 2007 the Company entered into a Consent Decree with
the United
States Environmental Protection Agency (EPA) in settlement of alleged violations of the Clean
Water Act, as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the Company paid
$504,000 in civil penalties for alleged discharges of crude oil into navigable waters or adjoining
shorelines from the Companys operations at the Weeks Island field in Iberia Parish, Louisiana. The
Company will also be subject to certain injunctive relief, requiring the Company to enhance certain
pipeline survey, monitoring and reporting activities. Under the Consent Decree, the Company does
not admit any liability arising out of the occurrences described in the Consent Decree or the
related Complaint. In 2007, the Company recorded an expense for the above amount in oil and
natural gas operating expenses.
Litigation involving insurable issues. There are no material legal proceedings involving insurable
issues which exceed 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 Companys risk factors, see Item 1A, Risk Factors, in the Companys Form
10-K for the year ended December 31, 2007. There have been no changes to these risk factors during
the quarter ended March 31, 2008.
ITEM 6. Exhibits.
|
|
|
3.1
|
|
Amended and Restated Bylaws of The Meridian Resource Corporation, as
amended. |
|
|
|
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: May 12, 2008 |
By: |
/s/ LLOYD V. DELANO
|
|
|
|
Lloyd V. DeLano |
|
|
|
Senior Vice President
Chief Accounting Officer |
|
|
31
Index to Exhibits
|
|
|
3.1
|
|
Amended and Restated Bylaws of The Meridian Resource Corporation, as
amended. |
|
|
|
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. |
32