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: June 30, 2007
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
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77077 |
(Address of principal executive offices)
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(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, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one)
Large Accelerated Filer o Accelerated Filer þ Non-Accelerated Filer 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 July 31, 2007: 89,350,558
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 |
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Six Months Ended |
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June 30, |
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June 30, |
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2007 |
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2006 |
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2007 |
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2006 |
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REVENUES: |
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Oil and natural gas |
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$ |
39,716 |
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$ |
45,101 |
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$ |
79,859 |
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$ |
102,928 |
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Price risk management activities |
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4 |
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1,003 |
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16 |
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363 |
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Interest and other |
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321 |
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436 |
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745 |
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755 |
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40,041 |
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46,540 |
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80,620 |
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104,046 |
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OPERATING COSTS AND EXPENSES: |
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Oil and natural gas operating |
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6,988 |
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5,011 |
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14,755 |
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9,564 |
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Severance and ad valorem taxes |
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2,619 |
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2,610 |
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5,463 |
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5,345 |
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Depletion and depreciation |
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19,607 |
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27,671 |
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40,610 |
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57,170 |
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General and administrative |
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3,890 |
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4,405 |
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7,785 |
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9,516 |
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Accretion expense |
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574 |
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319 |
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1,127 |
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620 |
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Hurricane damage repairs |
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404 |
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2,403 |
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33,678 |
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40,420 |
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69,740 |
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84,618 |
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EARNINGS BEFORE INTEREST AND INCOME TAXES |
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6,363 |
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6,120 |
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10,880 |
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19,428 |
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OTHER EXPENSE: |
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Interest expense |
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1,538 |
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1,489 |
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3,077 |
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2,867 |
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EARNINGS BEFORE INCOME TAXES |
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4,825 |
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4,631 |
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7,803 |
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16,561 |
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INCOME TAXES: |
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Current |
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(26 |
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197 |
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112 |
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368 |
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Deferred |
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2,146 |
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1,591 |
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3,318 |
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6,019 |
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2,120 |
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1,788 |
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3,430 |
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6,387 |
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NET EARNINGS |
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$ |
2,705 |
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$ |
2,843 |
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$ |
4,373 |
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$ |
10,174 |
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NET EARNINGS PER SHARE: |
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Basic |
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$ |
0.03 |
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$ |
0.03 |
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$ |
0.05 |
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$ |
0.12 |
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Diluted |
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$ |
0.03 |
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$ |
0.03 |
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$ |
0.05 |
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$ |
0.11 |
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WEIGHTED AVERAGE NUMBER OF COMMON SHARES: |
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Basic |
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89,329 |
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86,950 |
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89,291 |
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86,900 |
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Diluted |
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94,906 |
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92,140 |
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94,792 |
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92,346 |
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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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June 30, |
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December 31, |
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2007 |
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2006 |
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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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$ |
33,599 |
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$ |
31,424 |
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Restricted cash |
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28 |
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1,282 |
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Accounts receivable, less allowance for doubtful accounts of
$232 [2007 and 2006] |
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21,340 |
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24,285 |
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Due from affiliates |
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4,906 |
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670 |
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Prepaid expenses and other |
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7,965 |
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3,457 |
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Assets from price risk management activities |
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2,820 |
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7,968 |
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Total current assets |
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70,658 |
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69,086 |
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PROPERTY AND EQUIPMENT: |
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Oil and natural gas properties, full cost method (including
$59,384 [2007] and $54,356 [2006] not subject to
depletion) |
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1,709,815 |
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1,663,865 |
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Land |
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48 |
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48 |
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Equipment |
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10,813 |
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7,492 |
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1,720,676 |
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1,671,405 |
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Less accumulated depletion and depreciation |
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1,314,116 |
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1,273,522 |
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Total property and equipment, net |
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406,560 |
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397,883 |
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OTHER ASSETS: |
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Assets from price risk management activities |
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949 |
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490 |
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Other |
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215 |
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436 |
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Total other assets |
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1,164 |
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926 |
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TOTAL ASSETS |
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$ |
478,382 |
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$ |
467,895 |
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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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June 30, |
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December 31, |
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2007 |
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2006 |
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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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$ |
5,504 |
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$ |
6,700 |
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Advances from non operators |
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6,865 |
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3,051 |
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Revenues and royalties payable |
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8,990 |
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7,933 |
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Notes payable |
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6,818 |
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2,754 |
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Accrued liabilities |
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20,452 |
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21,938 |
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Liabilities from price risk management activities |
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1,274 |
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1,024 |
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Asset retirement obligations |
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3,863 |
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4,803 |
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Deferred income taxes payable |
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411 |
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2,336 |
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Current income taxes payable |
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30 |
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Total current liabilities |
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54,207 |
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50,539 |
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LONG TERM DEBT |
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75,000 |
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75,000 |
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OTHER: |
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Deferred income taxes |
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6,708 |
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3,364 |
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Liabilities from price risk management activities |
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662 |
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190 |
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Asset retirement obligations |
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18,818 |
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18,005 |
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26,188 |
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21,559 |
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STOCKHOLDERS EQUITY: |
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Common stock, $0.01 par value (200,000,000 shares authorized,
89,450,466 [2007] and 89,139,600 [2006] shares issued)
07] and 89,139,600 [2006] issued) |
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934 |
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928 |
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Additional paid in capital |
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536,309 |
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534,441 |
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Accumulated deficit |
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(214,906 |
) |
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(219,279 |
) |
Accumulated other comprehensive income |
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1,179 |
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4,707 |
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323,516 |
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320,797 |
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Less treasury stock, at cost 194,779 [2007] shares |
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(529 |
) |
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Total stockholders equity |
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322,987 |
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320,797 |
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TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
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$ |
478,382 |
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$ |
467,895 |
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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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Six Months Ended June 30, |
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2007 |
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2006 |
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CASH FLOWS FROM OPERATING ACTIVITIES: |
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Net earnings |
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$ |
4,373 |
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$ |
10,174 |
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Adjustments to reconcile net earnings to net cash
provided by operating activities: |
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Depletion and depreciation |
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40,610 |
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|
57,170 |
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Amortization of other assets |
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221 |
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221 |
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Non-cash compensation |
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1,360 |
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|
1,197 |
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Non-cash price risk management activities |
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(16 |
) |
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|
(363 |
) |
Accretion expense |
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|
1,127 |
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|
620 |
|
Deferred income taxes |
|
|
3,318 |
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|
6,019 |
|
Changes in assets and liabilities: |
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Restricted cash |
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1,254 |
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(19 |
) |
Accounts receivable |
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|
2,945 |
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|
14,261 |
|
Prepaid expenses and other |
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(4,508 |
) |
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(5,911 |
) |
Due from affiliates |
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|
(4,236 |
) |
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|
(1,825 |
) |
Accounts payable |
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|
(1,196 |
) |
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(2,460 |
) |
Advances from non-operators |
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3,814 |
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|
651 |
|
Revenues and royalties payable |
|
|
1,057 |
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(1,799 |
) |
Asset retirement obligations |
|
|
(1,791 |
) |
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|
(590 |
) |
Other assets and liabilities |
|
|
(814 |
) |
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|
(2,400 |
) |
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|
|
|
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Net cash provided by operating activities |
|
|
47,518 |
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|
|
74,946 |
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CASH FLOWS FROM INVESTING ACTIVITIES: |
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Additions to property and equipment |
|
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(51,280 |
) |
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|
(64,472 |
) |
Proceeds from sale of property |
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|
2,530 |
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|
10,741 |
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|
|
|
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Net cash used in investing activities |
|
|
(48,750 |
) |
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|
(53,731 |
) |
|
|
|
|
|
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CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Reductions in long-term debt |
|
|
|
|
|
|
(10,000 |
) |
Reductions in notes payable |
|
|
(4,895 |
) |
|
|
(3,065 |
) |
Proceeds from notes payable |
|
|
8,959 |
|
|
|
7,919 |
|
Repurchase of common stock |
|
|
(657 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
3,407 |
|
|
|
(5,146 |
) |
|
|
|
|
|
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS |
|
|
2,175 |
|
|
|
16,069 |
|
Cash and cash equivalents at beginning of period |
|
|
31,424 |
|
|
|
23,265 |
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
33,599 |
|
|
$ |
39,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION |
|
|
|
|
|
|
|
|
Non-cash activities: |
|
|
|
|
|
|
|
|
Issuance of shares for contract services |
|
$ |
(642 |
) |
|
$ |
(588 |
) |
ARO liability new wells drilled |
|
$ |
321 |
|
|
$ |
109 |
|
ARO liability changes in estimates |
|
$ |
216 |
|
|
$ |
694 |
|
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Six Months Ended June 30, 2007 and 2006
(in thousands of dollars and shares)
(unaudited)
|
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|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
Accumulated |
|
|
Other |
|
|
Unamortized |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Earnings |
|
|
Comprehensive |
|
|
Deferred |
|
|
Treasury Stock |
|
|
|
|
|
|
Shares |
|
|
Par Value |
|
|
Capital |
|
|
(Deficit) |
|
|
Income (Loss) |
|
|
Compensation |
|
|
Shares |
|
|
Cost |
|
|
Total |
|
Balance, December 31, 2005 |
|
|
86,818 |
|
|
$ |
900 |
|
|
$ |
524,692 |
|
|
$ |
(145,395 |
) |
|
$ |
(2,314 |
) |
|
$ |
(318 |
) |
|
|
|
|
|
$ |
|
|
|
$ |
377,565 |
|
Effect of adoption of FAS123R |
|
|
|
|
|
|
|
|
|
|
(318 |
) |
|
|
|
|
|
|
|
|
|
|
318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of rights to common stock |
|
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 401(k) plan contribution |
|
|
45 |
|
|
|
1 |
|
|
|
184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- - |
|
|
|
185 |
|
Stock-based compensation FAS123R |
|
|
|
|
|
|
|
|
|
|
167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
167 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
845 |
|
Accum. other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,351 |
|
Issuance of shares for contract services |
|
|
162 |
|
|
|
2 |
|
|
|
586 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
588 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2006 |
|
|
87,025 |
|
|
$ |
905 |
|
|
$ |
526,154 |
|
|
$ |
(135,221 |
) |
|
$ |
1,037 |
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
$ |
392,875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006 |
|
|
89,140 |
|
|
$ |
928 |
|
|
$ |
534,441 |
|
|
$ |
(219,279 |
) |
|
$ |
4,707 |
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
$ |
320,797 |
|
Issuance of rights to common stock |
|
|
|
|
|
|
4 |
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 401(k) plan contribution |
|
|
97 |
|
|
|
|
|
|
|
137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55 |
) |
|
|
128 |
|
|
|
265 |
|
Shares repurchased |
|
|
(250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250 |
|
|
|
(657 |
) |
|
|
(657 |
) |
Stock-based compensation FAS123R |
|
|
|
|
|
|
|
|
|
|
164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
164 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
846 |
|
Accum. other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,528 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,528 |
) |
Issuance of shares for contract services |
|
|
237 |
|
|
|
2 |
|
|
|
640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
642 |
|
Issuance of shares as compensation
stock |
|
|
31 |
|
|
|
|
|
|
|
85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2007 |
|
|
89,255 |
|
|
$ |
934 |
|
|
$ |
536,309 |
|
|
$ |
(214,906 |
) |
|
$ |
1,179 |
|
|
$ |
|
|
|
|
195 |
|
|
$ |
(529 |
) |
|
$ |
322,987 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
7
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Net earnings |
|
$ |
2,705 |
|
|
$ |
2,843 |
|
|
$ |
4,373 |
|
|
$ |
10,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax, for unrealized
gains (losses) from hedging activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gains (losses) arising during
period (1) |
|
|
849 |
|
|
|
1,761 |
|
|
|
(2,082 |
) |
|
|
2,605 |
|
Reclassification adjustments on settlement of
contracts (2) |
|
|
(243 |
) |
|
|
(14 |
) |
|
|
(1,446 |
) |
|
|
746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
606 |
|
|
|
1,747 |
|
|
|
(3,528 |
) |
|
|
3,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
$ |
3,311 |
|
|
$ |
4,590 |
|
|
$ |
845 |
|
|
$ |
13,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) net income tax (expense) benefit |
|
$ |
(457 |
) |
|
$ |
(948 |
) |
|
$ |
1,121 |
|
|
$ |
(1,403 |
) |
(2) net income tax (expense) benefit |
|
$ |
131 |
|
|
$ |
7 |
|
|
$ |
778 |
|
|
$ |
(401 |
) |
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, 2006, as filed with the Securities and Exchange Commission.
The financial statements included herein as of June 30, 2007, and for the three and six month
periods ended June 30, 2007 and 2006, 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. 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 Statement
is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 is
not expected to have a material impact, if any, on the Companys financial statements.
3. ACCRUED LIABILITIES
Below is the detail of accrued liabilities on the Companys balance sheets as of June 30, 2007 and
December 31, 2006 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
Capital expenditures |
|
$ |
12,400 |
|
|
$ |
13,851 |
|
Operating expenses/taxes |
|
|
5,127 |
|
|
|
4,024 |
|
Hurricane damage repairs |
|
|
|
|
|
|
71 |
|
Compensation |
|
|
819 |
|
|
|
1,197 |
|
Interest |
|
|
485 |
|
|
|
506 |
|
Other |
|
|
1,621 |
|
|
|
2,289 |
|
|
|
|
|
|
|
|
Total |
|
$ |
20,452 |
|
|
$ |
21,938 |
|
|
|
|
|
|
|
|
4. 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
9
LLC and Standard Bank
PLC completed the syndication group, collectively the Lenders. The current borrowing base under
the Credit Facility was determined to be $115 million by the syndication group effective April 30,
2007. As of June 30, 2007, outstanding borrowings under the Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and
October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations,
the Lenders or the Company have the right to redetermine the borrowing base at any time, provided
that no party can request more than one such redetermination between the regularly scheduled
borrowing base redeterminations. 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 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 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, all of which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative base rate loan that
bears interest at a rate per annum equal to the greater of the administrative agents prime rate;
or (b) federal funds-based rate plus 1/2 of 1%, plus an additional 0.5% to 1.25% depending on the
ratio of the aggregate outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum equal to the London
interbank offered rate (LIBOR) plus 1.5% to 2.25%, depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base. At June 30, 2007, the three-month
LIBOR interest rate was 5.36%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate outstanding loans under
the Credit Facility.
5. INCOME TAXES
In July 2006, the FASB issued FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in
Income Taxes an Interpretation of SFAS No. 109. 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 position.
6. COMMITMENTS AND CONTINGENCIES
Litigation.
H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for damages estimated to exceed several million dollars for Meridians alleged gross
negligence, willful
10
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 has 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. Bond has recently died. The Company has not provided any amount for
this matter in its financial statements at June 30, 2007.
Title/lease disputes. Title and lease disputes arise due to various events that have
occurred in the various states in which the Company operates. These disputes are usually small but
could lead to the Company over- or under-stating reserves prior to when 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. The Company, in certain instances, has indemnified third parties from the claims made
in these lawsuits. In three of the lawsuits, Shell Oil Company and SWEPI LP have demanded indemnity
and defense from Meridian; Meridian has denied such demands. The Company has not provided any
amount for this matter in its financial statements at June 30, 2007.
During the third quarter of 2007 the Company expects to enter into a Consent Decree with the United
States Environmental Protection Agency (EPA) regarding alleged violations of the Clean Water Act,
as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the Company will pay
$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 conduct 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. During the second quarter of 2007, the Company recorded an expense for the
above amount in oil and natural gas operating expenses.
Litigation involving insurable issues. There are no other material legal proceedings which exceed
our insurance limits to which Meridian or any of its subsidiaries is a party or to which any of its
property is subject, other than ordinary and routine litigation incidental to the business of
producing and exploring for crude oil and natural gas.
Commitments. The Company has an agreement for the construction and purchase of one newly built
land based drilling rig with an engineering design and fabrication/rig contractor, for
approximately $12 million. This contractor will ultimately operate, crew and maintain the rig.
Delivery of the rig is currently expected in the fourth quarter of 2007 when the rig will be
mobilized to the Companys East Texas Austin Chalk play. As of June 30, 2007, approximately $3.5
million has been capitalized as Equipment in the accompanying consolidated balance sheets.
7. COMMON STOCK
In March 2007, the Companys Board of Directors authorized a new 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 the next 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
11
approved by the Lenders, subject to certain
restrictive covenants. As of June 30, 2007, the Company had repurchased 250,000 common shares at a
cost of $657,000. It is the intent of the Company to continue this program through this and future
years.
8. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted net earnings per share (in
thousands, except per share):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
|
2007 |
|
|
2006 |
|
Numerator: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
2,705 |
|
|
$ |
2,843 |
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share weighted-average shares outstanding |
|
|
89,329 |
|
|
|
86,950 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
Warrants |
|
|
5,576 |
|
|
|
5,079 |
|
Employee and director stock options |
|
|
1 |
|
|
|
111 |
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share -
weighted-average shares outstanding
and assumed conversions |
|
|
94,906 |
|
|
|
92,140 |
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
0.03 |
|
|
$ |
0.03 |
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
0.03 |
|
|
$ |
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2007 |
|
|
2006 |
|
Numerator: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
4,373 |
|
|
$ |
10,174 |
|
Denominator: |
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share weighted-average shares outstanding |
|
|
89,291 |
|
|
|
86,900 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
Warrants |
|
|
5,501 |
|
|
|
5,027 |
|
Employee and director stock options |
|
|
|
|
|
|
419 |
|
|
|
|
|
|
|
|
Denominator for diluted earnings per
share weighted-average shares outstanding
and assumed conversions |
|
|
94,792 |
|
|
|
92,346 |
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
0.05 |
|
|
$ |
0.12 |
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
0.05 |
|
|
$ |
0.11 |
|
|
|
|
|
|
|
|
9. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments with value fluctuations that correlate
strongly with the underlying commodity being hedged. From time to time, 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
12
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 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 gains related to hedge ineffectiveness of approximately $4 thousand and $1.0 million
during the three months ended June 30, 2007 and 2006, respectively, and of approximately $16
thousand and $363 thousand during the six months ended June 30, 2007 and 2006, respectively.
The estimated June 30, 2007 fair value of the Companys oil and natural gas derivatives resulted in
an unrealized gain of $1.8 million ($1.2 million net of tax) which is recognized in accumulated
other comprehensive income. Based upon June 30, 2007 oil and natural gas commodity prices,
approximately $1.5 million of the gain deferred in accumulated other comprehensive income could
potentially increase gross revenues over the next twelve months. These derivative agreements
expire at various dates through December 31, 2008.
Net settlements under these contracts increased (decreased) oil and natural gas revenues by
$374,000 and $21,000 for the three months ended June 30, 2007 and 2006, respectively, and by
$2,224,000 and ($1,147,000) for the six months ended June 30, 2007 and 2006, respectively, as a
result of hedging transactions.
The Company has entered into certain derivative contracts as summarized in the table below. The
notional amount is equal to the total net volumetric hedge position of the Company during the
periods presented. As of June 30, 2007, the positions effectively hedge approximately 33% of the
estimated proved developed natural gas production and 26% of the estimated proved developed oil
production during the respective terms of the hedging agreements. The fair values of the hedges
are based on the difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
13
The fair value of the hedging agreements is recorded on the consolidated balance sheet as assets or
liabilities from price risk management activities. The estimated fair value of the hedging
agreements as of June 30, 2007, is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Price |
|
|
June 30, 2007 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 2007 Dec 2007 |
|
Collar |
|
|
2,460,000 |
|
|
$ |
7.00 |
|
|
$ |
11.50 |
|
|
$ |
920 |
|
Jan 2008 Dec 2008 |
|
Collar |
|
|
2,230,000 |
|
|
$ |
7.00 |
|
|
$ |
12.15 |
|
|
|
523 |
|
Jan 2008 Dec 2008 |
|
Collar |
|
|
1,010,000 |
|
|
$ |
7.50 |
|
|
$ |
11.50 |
|
|
|
358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas
|
|
|
1,801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 2007 |
|
Collar |
|
|
12,000 |
|
|
$ |
50.00 |
|
|
$ |
74.00 |
|
|
|
(12 |
) |
Jan 2008 Dec 2008 |
|
Collar |
|
|
40,000 |
|
|
$ |
55.00 |
|
|
$ |
83.00 |
|
|
|
(102 |
) |
Aug 2007 April 2008 |
|
Collar |
|
|
54,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(46 |
) |
May 2008 July 2008 |
|
Collar |
|
|
15,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(25 |
) |
July 2007 |
|
Collar |
|
|
3,000 |
|
|
$ |
60.00 |
|
|
$ |
96.10 |
|
|
|
|
|
May 2008 July 2008 |
|
Collar |
|
|
52,000 |
|
|
$ |
65.00 |
|
|
$ |
93.15 |
|
|
|
91 |
|
Aug 2007 July 2008 |
|
Collar |
|
|
40,000 |
|
|
$ |
70.00 |
|
|
$ |
87.40 |
|
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil
|
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,833 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10. STOCK-BASED COMPENSATION
Stock Options
Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, Shared-Based
Payment, using the modified prospective method. SFAS No. 123R replaces SFAS No. 123, Accounting
for Stock-Based Compensation and amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R
addresses the accounting for share-based payment transactions in which an enterprise received
employee services in exchange for: (a) equity instruments of the enterprise or (b) liabilities that
are based on the fair value of the enterprises equity instruments or that may be settled by the
issuance of such equity instruments. SFAS No. 123R eliminates the ability to account for
share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees, and generally requires instead that such transactions
be accounted for using the fair-value based method. Prior to adoption of SFAS No. 123R, the
Company followed the intrinsic value method in accordance with APB No. 25 to account for stock
options.
Compensation expense is recorded for stock option awards over the requisite vesting periods based
upon the market value on the date of the grant. Stock-based compensation expense of approximately
$77,000 and $164,000 was recorded in the three months and six months ended June 30, 2007,
respectively, and approximately $85,000 and $167,000 was recognized in the three months and six
months ended June 30, 2006, respectively.
14
11. 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 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 six
months ended June 30, 2007, and for the year ended December 31, 2006 (thousands of dollars):
|
|
|
|
|
Asset retirement obligation at December 31, 2005 |
|
$ |
11,964 |
|
|
|
|
|
|
Additional retirement obligations recorded in 2006 |
|
|
4,559 |
|
Settlements during 2006 |
|
|
(6,026 |
) |
Revisions to estimates and other changes during 2006 |
|
|
10,723 |
|
Accretion expense for 2006 |
|
|
1,588 |
|
|
|
|
|
Asset retirement obligation at December 31, 2006 |
|
|
22,808 |
|
|
|
|
|
|
Additional retirement obligations recorded in 2007 |
|
|
321 |
|
Settlements during 2007 |
|
|
(1,791 |
) |
Revisions to estimates and other changes during 2007 |
|
|
216 |
|
Accretion expense for 2007 |
|
|
1,127 |
|
|
|
|
|
Asset retirement obligation at June 30, 2007 |
|
$ |
22,681 |
|
|
|
|
|
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.
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. In recognition of
the maturity of the Companys traditional producing region and the paradigm of crude oil and
natural gas pricing, management modified its business strategy while retaining its position in the
Gulf Coast region of south Louisiana and Texas and leveraged off the higher cash flows generated
from these properties to acquire exploration opportunities with large acreage positions, multiple
repeatable wells and longer-lived reserves. These include East Texas, Texas Gulf Coast and
Offshore, Mid-Continent, South Louisiana and Offshore, and unconventional resources.
15
Operations Overview. The Company is on track with the execution of its business plan and
aggressively pursuing its drilling with other growth activities whereby it has set targeted
spending of $127 million during 2007. As an integral part of these efforts, the Company has
created a balanced portfolio of projects that it believes will reduce its risk profile, thereby
improving success, and maintain its exposure to its historical high returns of and on capital
deployed while at the same time developing longer lived reserves.
East Texas Area
This play holds the potential for becoming a significant resource play for the Company with a
strong lease acreage position that will support a repeatable, multiple well-drilling and
development program for the foreseeable future. Results from initial drilling activities in this
key area have already made this a significant contributor to the Companys plans for return to
growth through increases in both production and reserves.
The Company and its joint venture partners currently hold approximately 38,000 gross acres in the
play. Meridian continues to increase its position in this very competitive area and anticipates
being able to add an additional 15,000 to 20,000 acres in the coming months. With the increased
acreage position, the number of possible drilling locations increases in general terms to between
50 and 55 wells. Assuming continued success in the expansion of the play, the Company anticipates
that it will maintain two rigs in this region until the play is fully developed. Meridian is the
operator of the field, and, depending on participations and acreage contributions, will hold up to
75% working interest in each unit.
The Blackstone Minerals (BSM) No. 4 well has reached its total depth (TD). The single lateral
well was drilled vertically to approximately 13,000 feet with the horizontal portion extending out
approximately 5,500 feet for a total measured depth of approximately 18,500 feet. The well will be
completed during August 2007 after which the well will be tested.
The BSM No. 2 well is currently drilling at approximately 15,700 feet MD. The single lateral well
was drilled vertically to approximately 13,100 feet with the horizontal portion currently extending
out approximately 2,600 feet. The targeted length for the lateral is 6,000 feet. Mechanical issues
associated with the rig being used for this well and, separately, third party downhole directional
tools, have caused delays in the length of time previously estimated to drill and complete this
well. However, the Company has worked diligently with the owners of the rig to make the necessary
repairs and expects improved progress in the rate of drilling going forward. The horizontal lateral
is expected to reach TD during the third quarter of 2007.
The Company is participating in the Bear Creek No. 1-H well, which is currently drilling at
approximately 14,000 feet MD on the first of two scheduled laterals approximately five miles
northeast of Meridians operating area. Meridian holds approximately 7% working interest in this
outside operated well.
The next wells scheduled for drilling in this area are the Freeman No. 1 well and the BSM No. 5
well. Each well is scheduled to drill and complete dual horizontal laterals extending roughly north
and south between 5,000 and 6,000 feet each. The BSM No. 5 well is located approximately 1.5 miles
northwest of the BSM No. 4 well. The Freeman No. 1 well is located approximately 4 miles northwest
of the BSM No. 4 well.
The previously announced purchase and construction of one newly built land based drilling rig is on
track for delivery. The rig is being designed and fabricated by Orion Drilling Company LP in Corpus
Christi, Texas. The rig will be operated, crewed and maintained by Orion. Delivery of the rig is
currently expected in the fourth quarter of 2007 when it will be mobilized to the Companys East
Texas Austin Chalk play. Depending on the success of the operations in the play, the Company has
plans for a two-rig, multi-well drilling program to exploit and develop the Companys acreage under
lease for an anticipated three to seven year period.
16
Texas Gulf Coast and Offshore
In August of 2006, the Company purchased all of the Texas Gulf Coast assets of Vintage Petroleum
LLC for approximately $21 million in cash and stock. The assets were comprised of both producing
properties as well as exploration and exploitation properties as identified on the proprietary and
acquired 3-D seismic data over the properties. Since the purchase, Meridian has participated in six
wells in the area including one well that is currently drilling with one more still budgeted for
2007. Six additional prospective well locations have emerged as a result of the successful drilling
in this area.
The Company recently participated in the outside operated ST 974 No. 2 well located in Nueces Bay
in San Patricio County, Texas (northeast of Corpus Christi). The well targeted a shallow Frio sand
in a separate fault block of the East White Point field. The well was drilled to approximately
6,400 feet MD and logged prospective pay in the Frio sand section at 6,300 feet with two additional
prospective sands (including the Brigham sand) above it. The well was recently tested in the 6,300
sand section at a gross daily flow rate of 90 barrels of oil per day and 120 Mcf per day. The well
is currently producing oil into sales. The primary objective sand, the Brigham sand, is scheduled
to be tested in the next couple of weeks. If successful, the well will co-mingle production from
both the 6,300 sand and the Brigham sand. Depending on the results of testing and production, it
is anticipated that this prospect can be offset with an additional development well. The Company
owns approximately 23% working interest in the well and its offset.
The outside operated ST 976 No. 2 well on the East White Point prospect located in the Nueces Bay
project area is being drilled to test several deep Frio sands. These are the same sands that were
successfully exploited in the previously drilled B.P. America well during the fourth quarter of
2006. This well is currently at approximately 10,700 feet on its way to a total depth of
approximately 13,000 feet MD. Meridian owns approximately 23% working interest in this well.
The ST 786 No. 12 well on the Indian Point prospect located in the Nueces Bay project area was
fracture stimulated in one of two deep Anderson sand sections of the lower Frio formation. The
results of the fracture stimulation were in and of themselves uneconomic. Therefore, operations
were begun to move up the hole to test and fracture stimulate the upper portion of the Anderson
(Frio) sand. During the preparations for the next test, downhole tools became stuck in the deviated
hole which has required several weeks of time to clear and retrieve. The retrieval process is
nearly complete and the Company expects to be moving forward shortly with its plans to exploit the
remaining uphole sands.
The Company recently drilled the High Island 55 No. 7 well, located in the shallow offshore waters
of the Texas Gulf Coast. The well was drilled to approximately 8,000 feet targeting the Siph D A
sand section. The well was logged with the results showing sands that contained no hydrocarbons.
The well was plugged and abandoned.
Mid-Continent
In the Mid-Continent region of north central Oklahoma, the Company is proceeding with plans to
develop its approximately 22,000 acre position in the Hunton/Woodford de-watering play pilot
project. Since acquiring the leases, the company has drilled four wells including one saltwater
disposal well. Of the three gas wells drilled to date, the Constellation 8-2 well was successfully
completed in the Mississippian formation.
The other two wells (Constellation No. 8-1 and Enterprise No. 7-1) were determined be depleted in
the Hunton formation, rendering them uneconomic in that zone. Subsequent to this determination, and
its affects on the acreage surrounding these wells, the Company has adjusted its original 2007
budgeted plans of fourteen total wells for this area to a lesser number depending on further
testing and results. During the course of the next five months, the Company has plans to drill up
to four additional wells with the possibility of more to follow depending on the success of those
tests. The Company still believes this is a good prospective area and recognizes it as a
potentially important component of its overall strategic plan for long term growth and asset
diversification. Meridian operates the field and owns approximately 80% working interest.
17
South Louisiana and Offshore
South Louisiana remains a core area for Meridian where it has built a large knowledge and
information base that it believes holds significant value for the development of future projects
and significant potential for increased reserves and production during 2007. Although the Company
is expanding beyond its traditional footprint of South Louisiana, it continues to be a core area
for growth and a strategic part of the Companys portfolio management by generating and
participating in the drilling of targets for larger reserves with strong cash flows. Several
projects remain to be tested during 2007 to complete the Companys planned capital spending for
this region.
In offshore Gulf of Mexico, the Company is drilling a prospect on its West Cameron Block 332
project area located in the federal offshore waters approximately 50 miles off the southwest coast
of Louisiana. Currently the well is at a depth of approximately 8,100 feet MD headed for the
targeted formation in the Upper Miocene sand at a depth of approximately 13,800 feet. The gross
unrisked reserve potential for this prospect is approximately 15 to 30 Bcfe. Meridian owns 17%
working interest before casing point and 37% working interest after casing point and is the
operator of the well. If successful, it is contemplated that at least one additional well will be
drilled on this lease block.
Deep Archtop
The Company continues to develop its Deep Archtop prospect for drilling. The project is designed to
test a Jurassic Cotton Valley four-way closure in the Biloxi Marshlands area of St. Bernard Parish,
Louisiana. This 30,000-foot prospect has over 14,400 acres of closure, imaged by 3-D seismic and
offers reserve potential of up to 5-7 trillion cubic feet of gas.
The Company has acquired additional acreage over the play from both the State of Louisiana and
multiple landowners in the vicinity. In addition, meetings with both State of Louisiana agencies
and local governmental authorities have been held with positive results that support the Companys
planned routes, drilling location and timing. The Company will spend the coming year in pre-drill
work, followed by 300-plus days to drill the well which is estimated to cost up to $60 million. The
shallow marshlands water location provides the potential for significant savings in drilling the
test well and post development infrastructure compared to similarly sized offshore projects which
typically cost much more and require longer periods of time to construct the necessary pipelines
and production facilities. Meridian owns production facilities and pipelines in the immediate area.
Meridian intends to retain and pay its share of approximately 20-25% working interest in this
well. The Company has set a target date of mid-year 2008 for initiating drilling operations on this
significant test well.
Unconventional Resource Plays
The Companys push for diversity and growth continues to develop in the Delaware Basin, Palo Duro
Basin and Illinois Basin.
In the Delaware Basin, the Company and its joint venture partner have completed their evaluation of
the previously acquired 2D seismic in the area and have selected the first two locations to be
drilled in the fourth quarter. These wells will target the Barnett and Woodford Shale sections
which range between 5,500 and 8,500 feet. Targeted reserves range between 2 and 3 Bcf per well.
Meridians 50% joint venture partner will operate substantially all of the drilling and production
for the project. The group owns approximately 85,000 acres in the area and anticipates that it will
drill a minimum of two wells during 2007.
In the New Albany Shale Play in the Illinois Basin, the Company continues to acquire leases and
currently owns an approximate 30,000-acre lease position. Meridian has plans for two wells in this
area between now and the end
of the year. The Companys working interest in the play is 92% with Meridian as operator.
18
In the Palo Duro Basin Play, the Company owns approximately 35,000 gross acres. Several operators
in the basin are in various stages of testing optimal drilling and completion techniques for wells
in the area, with reported successful results. The Company owns 92% working interest in the play
and is currently developing a plan for drilling operations in this region.
Other Conditions
Industry Conditions. Revenues, profitability and future growth rates of Meridian are substantially
dependent upon prevailing prices for oil and natural gas. Oil and natural gas prices have been
extremely volatile in recent years and are affected by many factors outside of our control. Our
average oil price (after adjustments for hedging activities) for the three months ended June 30,
2007, was $61.20 per barrel compared to $56.01 per barrel for the three months ended June 30, 2006,
and $50.30 per barrel for the three months ended March 31, 2007. Our average natural gas price
(after adjustments for hedging activities) for the three months ended June 30, 2007, was $7.77 per
Mcf compared to $7.29 per Mcf for the three months ended June 30, 2006, and $7.34 per Mcf for the
three months ended March 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.
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, 2006, for further discussion.
Results of Operations
Three Months Ended June 30, 2007 Compared to Three Months Ended June 30, 2006
Operating Revenues. Second quarter 2007 oil and natural gas revenues, which include oil and
natural gas hedging activities (see Note 9 of Notes to Consolidated Financial Statements),
decreased $5.4 million (12%) as compared to second quarter 2006 revenues due to a 19% decrease in
production volumes partially offset by a 9% increase in average commodity prices on a natural gas
equivalent basis. Oil and natural gas production volumes totaled 4,734 Mmcfe for the second quarter
of 2007 compared to 5,850 Mmcfe for the comparable period of 2006. Our average daily production
decreased from 64.3 Mmcfe during the second quarter of 2006 to 52.0 Mmcfe for the second quarter of
2007. The variance in production volumes between the two periods is primarily due to natural
production declines and mechanical issues in the Weeks Island field, partially offset by production
from new discoveries brought online since the second quarter of 2006.
19
The following table summarizes the Companys operating revenues, production volumes and
average sales prices for the three months ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
June 30, |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
|
201 |
|
|
|
199 |
|
|
|
1 |
% |
Natural gas (MMcf) |
|
|
3,526 |
|
|
|
4,657 |
|
|
|
(24 |
%) |
Mmcfe |
|
|
4,734 |
|
|
|
5,850 |
|
|
|
(19 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
61.20 |
|
|
$ |
56.01 |
|
|
|
9 |
% |
Natural gas (per Mcf) |
|
$ |
7.77 |
|
|
$ |
7.29 |
|
|
|
7 |
% |
Mmcfe |
|
$ |
8.39 |
|
|
$ |
7.71 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues (000s): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
12,314 |
|
|
$ |
11,145 |
|
|
|
10 |
% |
Natural gas |
|
|
27,402 |
|
|
|
33,956 |
|
|
|
(19 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues |
|
$ |
39,716 |
|
|
$ |
45,101 |
|
|
|
(12 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $2.0
million (39%) to $7.0 million during the second quarter of 2007, compared to $5.0 million in the
second quarter of 2006. On a unit basis, lease operating expenses increased $0.62 per Mcfe to $1.48
per Mcfe for the second quarter of 2007 from $0.86 per Mcfe for the second quarter of 2006. Oil and
natural gas operating expenses increased between the periods primarily due to significantly higher
insurance costs, industry wide increases in service costs and increased maintenance-related
activities. For the policy year beginning in May 2006 through April 2007 insurance premiums
increased over 450% from the prior policy year. During the second quarter of 2007 insurance
premiums increased by $0.6 million and represented 30% of the difference in lease operating
expenses between the quarters. During the second quarter of 2007 approximately $0.5 million has
been expensed due to a civil penalty arising from environmental litigation (see Note 6 to
Consolidated Financial Statements). The remaining $0.9 million increase in operating expense was
associated with the addition of new producing wells in East Texas and southern Louisiana and from
the Vintage acquisition, as well as additional costs related to Biloxi Marshlands area
production and facilities including compression, storage and repairs. Although the Companys
insurance costs rose for the period from May 2006 through April 2007, the premium for the policy
for May 2007 through April 2008 has decreased by approximately 30%. We continue to insure our
assets with improved coverage as a safeguard against losses for the Company in the event of another
hurricane. 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 totaled $2.6 million for the second
quarter of 2007, the same as the second quarter of 2006. For the second quarter of 2007, there was
an increase in oil volumes and prices and a higher natural gas tax rate that was offset by a
decrease in natural gas production. Meridians oil and natural gas production is primarily from
Louisiana, and is therefore subject to Louisiana severance tax. The current severance tax rates
for Louisiana are 12.5% of gross oil revenues and $0.373 per Mcf for natural gas, an increase from
$0.252 per Mcf for the second quarter of 2006. On an equivalent unit of production basis, severance
and ad valorem taxes increased to $0.55 per Mcfe from $0.45 per Mcfe for the three-month period.
Beginning July 1, 2007, the revised severance tax rate for natural gas production in Louisiana over
the next twelve months will be $0.269 per Mcf. This will significantly decrease the amount of
severance taxes being paid in future periods.
20
Depletion and Depreciation. Depletion and depreciation expense decreased $8.1 million (29%) during
the second quarter of 2007 to $19.6 million, from $27.7 million for the same period of 2006. This
was primarily the result of a decrease in the depletion rate as compared to the 2006 period and the
decrease in natural gas production. On a unit basis, depletion and depreciation expense decreased
by $0.59 per Mcfe, to $4.14 per Mcfe for the three months ended June 30, 2007, compared to $4.73
per Mcfe for the same period in 2006. The rate decrease between the periods was due to the impact
of the impairment of long-lived assets recognized during the third quarter of 2006.
General and Administrative Expense. General and administrative expense decreased $0.5 million
(12%) to $3.9 million compared to $4.4 million for 2006. The decrease between the periods was due
to lower accounting, legal and other professional fees and to decreased office rental rates. On an
equivalent unit of production basis, general and administrative expenses increased $0.07 per Mcfe
to $0.82 per Mcfe for the second quarter of 2007 compared to $0.75 per Mcfe for the comparable 2006
period primarily due to lower production rates between the periods. Stock-based compensation
expense of approximately $78,000 was recognized in the three months ended June 30, 2007 compared to
$85,000 for the three month period ended June 30, 2006.
Hurricane Damage Repairs. This reduction was due to no additional costs during the second quarter
of 2007 related to the repairs of damages incurred from the 2005 hurricanes Katrina and Rita.
Interest Expense. Interest expense was $1.5 million for both the second quarter of 2007 and the
second quarter of 2006.
Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006
Operating Revenues. Oil and natural gas revenues during the six months ended June 30, 2007, which
include oil and natural gas hedging activities (see Note 9 to Consolidated Financial Statements)
decreased $23.1 million (22%) as compared to first half 2006 revenues due to a 19% decrease in
production volumes and a 5% decrease in average sale prices on a natural gas equivalent basis. Our
average daily production decreased from 67.9 Mmcfe during the first six months of 2006 to 55.2
Mmcfe for the first six months of 2007. Oil and natural gas production volume totaled 9,991 Mmcfe
for the first six months of 2007, compared to 12,282 Mmcfe for the comparable period of 2006. The
variance in production volumes between the two periods is primarily due to natural production
declines and mechanical issues in the Weeks Island field, partially offset by production from new
discoveries brought online since the second quarter of 2006.
Since the third quarter of 2006, the Company has taken an aggressive approach to increase its
acreage position and drilling activities in East Texas and has contracted for the purchase of one
rig and a twelve-month lease of an additional rig that will better ensure an uninterrupted drilling
and completion schedule and the replacement of production and reserves. Although natural gas prices
for the industry in general have experienced a decline since the first half of 2006, the Companys
effective hedging strategy continues to partially insulate it against the total impact of such
price declines.
21
The following table summarizes the Companys operating revenues, production volumes and average
sales prices for the six months ended June 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
|
|
|
June 30, |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
|
450 |
|
|
|
423 |
|
|
|
6 |
% |
Natural gas (MMcf) |
|
|
7,290 |
|
|
|
9,744 |
|
|
|
(25 |
%) |
Mmcfe |
|
|
9,991 |
|
|
|
12,282 |
|
|
|
(19 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
55.17 |
|
|
$ |
52.43 |
|
|
|
5 |
% |
Natural gas (per Mcf) |
|
$ |
7.55 |
|
|
$ |
8.29 |
|
|
|
(9 |
%) |
Mmcfe |
|
$ |
7.99 |
|
|
$ |
8.38 |
|
|
|
(5 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues (000s): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
24,833 |
|
|
$ |
22,179 |
|
|
|
12 |
% |
Natural gas |
|
|
55,026 |
|
|
|
80,749 |
|
|
|
(32 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues |
|
$ |
79,859 |
|
|
$ |
102,928 |
|
|
|
(22 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $5.2
million (54%) to $14.8 million during the first six months of 2007, compared to $9.6 million in
2006. On a unit basis, lease operating expenses increased $0.70 per Mcfe to $1.48 per Mcfe for the
first six months of 2007 from $0.78 per Mcfe for the first half of 2006. Oil and natural gas
operating expenses increased between the periods primarily due to significantly higher insurance
costs, industry wide increases in service costs and increased maintenance-related activities. For
the policy year beginning in May 2006 through April 2007, insurance premiums increased over 450%
from the prior policy year. During the first six months of 2007 insurance premiums increased by
$2.0 million and represented 38% of the difference in lease operating expenses between the halves.
During the second quarter of 2007 approximately $0.5 million has been expensed due to a civil
penalty arising from environmental litigation (see Note 6 to Consolidated Financial Statements).
The remaining $2.7 million increase in operating expenses was associated with the addition and
acquisition of producing wells and additional costs related to Biloxi Marshlands area production
and facilities including compression, storage and repairs. Although the companys insurance costs
rose for the period from May 2006 through April 2007, the premium for the policy for May 2007
through April 2008 has decreased by approximately 30%. We continue to insure our assets with
improved coverage as a safeguard against losses for the Company in the event of another hurricane.
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 increased slightly for the first
six months of 2007 in comparison to the same period in 2006 primarily because of an increase in oil
volumes and prices and a higher natural gas tax rate, partially offset by a decrease in natural gas
production. 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 were $0.373 per Mcf for natural gas for the first six months of 2007, an
increase from $0.252 per Mcf for the first half of 2006. On an equivalent unit of production
basis, severance and ad valorem taxes increased to $0.55 per Mcfe from $0.44 per Mcfe for the
comparable six-month period. Beginning July 1, 2007, the revised severance tax rate for natural
gas production in Louisiana over the next twelve months will be $0.269 per Mcf. This will
significantly decrease the amount of severance taxes being paid in future periods.
Depletion and Depreciation. Depletion and deprecation expense decreased $16.6 million (29%) during
the first half of 2007 to $40.6 million, from $57.2 million for the same period of 2006. This was
primarily the
22
result of a decrease in the depletion rate as compared to the 2006 period, and the
decline in natural gas production. The rate
decrease between the periods was due to the impact of the impairment of long-lived assets
recognized during the third quarter of 2006. On a unit basis, depletion and depreciation expense
decreased by $0.59 per Mcfe, to $4.06 per Mcfe for the six months ended June 30, 2007, compared to
$4.65 per Mcfe for the same period in 2006.
General and Administrative Expense. General and administrative expense was $7.8 million for the
first six months of 2007 and for the same period in 2006 was $9.5 million. This decrease was
primarily due to reductions in contract and consulting services, other professional fees, legal
services and a decrease in office rent between the periods. On an equivalent unit of production
basis, general and administrative expenses increased $0.01 per Mcfe to $0.78 per Mcfe for the first
six months of 2007 compared to $0.77 per Mcfe for the comparable 2006 period. Stock-based
compensation expense of approximately $164,000 was recognized in the six months ended June 30, 2007
compared to $167,000 for the six month period ended June 30, 2006.
Hurricane Damage Repairs. This 2006 expense of $2.4 million is due to damages incurred from the
2005 hurricanes Katrina and Rita, primarily related to the Companys insurance deductible and costs
in excess of insured values.
Interest Expense. Interest expense increased $0.2 million (7%), to $3.1 million for the first six
months of 2007 in comparison to the first half of 2006. The increase is primarily a result of
increased interest rates.
Liquidity and Capital Resources
Working Capital. During the second quarter of 2007, Meridians capital expenditures were
internally financed with cash flow from operations and cash on hand. As of June 30, 2007, the
Company had a cash balance of $33.6 million and working capital of $16.5 million.
Cash Flows. Net cash provided by operating activities was $47.5 million for the six months ended
June 30, 2007, as compared to $74.9 million for the same period in 2006. The decrease of $27.4
million was primarily due to lower natural gas commodity prices and lower natural gas production
volumes.
Net cash used in investing activities was $48.8 million during the six months ended June 30, 2007,
versus $53.7 million in the first six months of 2006.
Cash flows provided by financing activities during the first six months of 2007 were $3.4 million,
compared to cash used in financing activities of $5.1 million during the first six months of 2006.
This increase in cash provided by financing activities was primarily due to the second quarter 2007
increase in notes payable issued in connection with the Companys annual insurance renewal.
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 Bankc PLC completed the syndication group,
collectively the Lenders. The borrowing base under the Credit Facility was redetermined to be
$115 million by the syndication group effective April 30, 2007. As of June 30, 2007, outstanding
borrowings under the Credit Facility totaled $75 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and
October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations,
the Lenders or the Company, have the right to redetermine the borrowing base at any time, provided
that no party can request more than one such redetermination between the regularly scheduled
borrowing base redeterminations. The
23
determination of our 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. Our Lenders can redetermine
the borrowing base to a lower level than the current borrowing base if they determine that our oil
and natural gas reserves, at the time of redetermination, are inadequate to support the borrowing
base then in effect.
Obligations under the Credit Facility are secured by pledges of outstanding capital stock of the
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 gas properties. In addition, the Company
is required to deliver to the Lenders and maintain satisfactory title opinions covering not less
than 70% of the present value of proved oil and natural gas properties. The Credit Facility also
contains other restrictive covenants, including, among other items, maintenance of certain
financial ratios, restrictions on cash dividends on common stock and under certain circumstances
preferred stock, limitations on the redemption of preferred stock and an unqualified audit report
on the Companys consolidated financial statements, all of which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative base rate loan that
bears interest at a rate per annum equal to the greater of the administrative agents prime rate;
or (b) federal funds-based rate plus 1/2 of 1%, plus an additional 0.5% to 1.25% depending on the
ratio of the aggregate outstanding loans and letters of credit to the borrowing base or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum equal to the London
interbank offered rate (LIBOR) plus 1.5% to 2.25%, depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base. At June 30, 2007, the three-month
LIBOR interest rate was 5.36%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate outstanding loans under
the Credit Facility.
Oil and Natural Gas Hedging Activities. The Company may address market risk by selecting
instruments with fluctuating values that correlate strongly with the underlying commodity being
hedged. From time to time we may enter into derivative contracts to hedge the price risks
associated with a portion of anticipated future oil and natural gas production. These contracts
allow the Company to predict with greater certainty the effective oil and natural gas prices to be
received for our hedged production. While the use of hedging arrangements limits the downside risk
of adverse price movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a fixed and a variable
product price. These agreements are settled in cash at or prior to expiration or exchanged for
physical delivery contracts. The Company does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk is minimal on
these transactions. In the event of nonperformance, the Company would be exposed to price risk.
The Company has some risk of accounting loss since the price received for the product at the actual
physical delivery point may differ from the prevailing price at the delivery point required for
settlement of the hedging transaction.
These hedging contracts have been designated as cash flow hedges as provided by SFAS No. 133 and
any changes in fair value of the cash flow hedge are reported in other comprehensive income except
that changes in fair value resulting from ineffectiveness of the hedge are reported in the
consolidated statement of operations as revenues.
24
Capital Expenditures. Total capital expenditures for this period were approximately $51.3 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 2007 capital expenditures plan is currently forecast at approximately $127 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 2007 plan utilizing cash flow from operations and cash on hand.
When appropriate, excess cash flow from operations beyond that needed for the 2007 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 June 30, 2007, we had a cushion (i.e. the
excess of the ceiling over our capitalized costs) of approximately $78 million (before tax).
26
Borrowing base for the Credit Facility. The Credit Agreement 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, 2007. 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.
27
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
The Company is currently exposed to market risk from hedging contracts changes and changes in
interest rates. A discussion of the market risk exposure in financial instruments follows.
Interest Rates
We are subject to interest rate risk on our long-term fixed interest rate debt and variable
interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the
Credit Facility. Since interest charged on borrowings under the Credit Facility floats with
prevailing interest rates (except for the applicable interest period for Eurodollar loans), the
carrying value of borrowings under the Credit Facility should approximate the fair market value of
such debt. Changes in interest rates, however, will change the cost of borrowing. Assuming $75
million remains borrowed under the Credit Facility, we estimate our annual interest expense will
change by $0.75 million for each 100 basis point change in the applicable interest rates utilized
under the Credit Agreement.
Hedging Contracts
Meridian may address market risk by selecting instruments whose value fluctuations correlate
strongly with the underlying commodity being hedged. From time to time, we may enter into
derivative contracts to hedge the price risks associated with a portion of anticipated future oil
and natural gas production. While the use of
hedging arrangements limits the downside risk of adverse price movements, it may also limit future
gains from favorable movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are settled in cash at
or prior to expiration or exchanged for physical delivery contracts. Meridian does not obtain
collateral to support the agreements, but monitors the financial viability of counter-parties and
believes its credit risk is minimal on these transactions. In the event of nonperformance, the
Company would be exposed to price risk. Meridian has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ from the prevailing price
at the delivery point required for settlement of the hedging transaction.
The Company has entered into certain derivative contracts as summarized in the table below. The
Notional Amount is equal to the total net volumetric hedge position of the Company during the
periods presented. As of June 30, 2007, the positions effectively hedge approximately 33% of the
estimated proved developed natural gas production and 26% of the estimated proved developed oil
production during the respective terms of the contracts. The fair values of the hedges are based
on the difference between the strike price and the New York Mercantile Exchange future prices for
the applicable trading months.
28
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Ceiling Price |
|
|
June 30, 2007 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 2007 Dec 2007 |
|
Collar |
|
|
2,460,000 |
|
|
$ |
7.00 |
|
|
$ |
11.50 |
|
|
$ |
920 |
|
Jan 2008 Dec 2008 |
|
Collar |
|
|
2,230,000 |
|
|
$ |
7.00 |
|
|
$ |
12.15 |
|
|
|
523 |
|
Jan 2008 Dec 2008 |
|
Collar |
|
|
1,010,000 |
|
|
$ |
7.50 |
|
|
$ |
11.50 |
|
|
|
358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas
|
|
|
1,801 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 2007 |
|
Collar |
|
|
12,000 |
|
|
$ |
50.00 |
|
|
$ |
74.00 |
|
|
|
(12 |
) |
Jan 2008 Dec 2008 |
|
Collar |
|
|
40,000 |
|
|
$ |
55.00 |
|
|
$ |
83.00 |
|
|
|
(102 |
) |
Aug 2007 April 2008 |
|
Collar |
|
|
54,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(46 |
) |
May 2008 July 2008 |
|
Collar |
|
|
15,000 |
|
|
$ |
60.00 |
|
|
$ |
82.00 |
|
|
|
(25 |
) |
July 2007 |
|
Collar |
|
|
3,000 |
|
|
$ |
60.00 |
|
|
$ |
96.10 |
|
|
|
|
|
May 2008 July 2008 |
|
Collar |
|
|
52,000 |
|
|
$ |
65.00 |
|
|
$ |
93.15 |
|
|
|
91 |
|
Aug 2007 July 2008 |
|
Collar |
|
|
40,000 |
|
|
$ |
70.00 |
|
|
$ |
87.40 |
|
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil
|
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,833 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 second quarter of
2007. 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 second quarter of 2007 that could significantly affect these controls.
Changes in Internal Controls
During the three month period ended June 30, 2007, 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.
29
PART II OTHER INFORMATION
ITEM 1. Legal Proceedings.
H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for damages estimated to exceed several million dollars for 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 has 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. Bond
has recently died. The Company has not provided any amount for this matter in its financial
statements at June 30, 2007.
Title/lease disputes. Title and lease disputes arise due to various events that have
occurred in the various states in which the Company operates. These disputes are usually small but
could lead to the Company over- or under-stating reserves prior to when 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. The Company, in certain instances, has indemnified third parties from the claims made
in these lawsuits. In three of the lawsuits, Shell Oil Company and SWEPI LP have demanded indemnity
and defense from Meridian; Meridian has denied such demands. The Company has not provided any
amount for this matter in its financial statements at June 30, 2007.
During the third quarter of 2007 the Company expects to enter into a Consent Decree with the United
States Environmental Protection Agency (EPA) regarding alleged violations of the Clean Water Act,
as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the Company will pay
$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 conduct 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. During the second quarter of 2007, the Company recorded an expense for the
above amount in oil and natural gas operating expenses.
Litigation involving insurable issues. There are no other material legal proceedings which exceed
our insurance limits to which Meridian or any of its subsidiaries is a party or to which any of its
property is subject, other than ordinary and routine litigation incidental to the business of
producing and exploring for crude oil and natural gas.
ITEM 1A. Risk Factors.
For a discussion of the Companys risk factors, see Item 1A, Risk Factors, in the Companys Form
10-K for the year ended December 31, 2006. There have been no changes to these risk factors during
the quarter ended June 30, 2007.
30
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
Following is a summary of our repurchase activity, for the three-month period ending June 30, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
Approximate Dollar Value |
|
|
Number of |
|
|
|
|
|
Total Number of Shares |
|
of Shares that May Yet Be |
|
|
Shares |
|
Average Price |
|
Purchased as Part of a |
|
Purchased Under the Plan |
Period |
|
Purchased |
|
Paid Per Share |
|
Publicly Announced Plan (a) |
|
During 2007 |
|
April 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 2007 |
|
|
100,000 |
|
|
$ |
3.05 |
|
|
|
100,000 |
|
|
$ |
4,343,000 |
|
|
Total |
|
|
100,000 |
|
|
$ |
3.05 |
|
|
|
100,000 |
|
|
$ |
4,343,000 |
|
|
|
|
|
(a) |
|
In March 2007, our Board of Directors authorized the repurchase in the open market or
through privately negotiated transactions up to $5 million worth of common shares per year over the
next 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. As of
June 30, 2007, the Company had repurchased 250,000 common shares in the open market at an aggregate
cost of $657,000. Such shares are reflected in the accompanying Consolidated Balance Sheet as
treasury stock. See Note 7 of the Notes to Consolidated Financial Statements. It is our intent
to continue this program through this and future years. |
ITEM 4. Submission of Matters to a Vote of Security Holders.
At the annual meeting of shareholders held on June 21, 2007, the Companys shareholders elected one
Class I Director and three Class II Directors. The following summarizes the votes for and withheld
for each nominee.
|
|
|
|
|
|
|
|
|
|
|
Nominee |
|
Class |
|
For |
|
Withheld |
C. Mark Pearson
|
|
I
|
|
|
65,644,701 |
|
|
|
10,900,617 |
|
E. L. Henry
|
|
II
|
|
|
63,043,927 |
|
|
|
13,501,391 |
|
Joe E. Kares
|
|
II
|
|
|
63,030,977 |
|
|
|
13,514,341 |
|
Gary Messersmith
|
|
II
|
|
|
64,541,096 |
|
|
|
12,094,222 |
|
Shareholders also voted to accept a proposal to adopt the 2007 Long Term Incentive Plan and a
proposal to approve the performance criteria for performance awards under the 2007 Long Term
Incentive Plan. The following summarizes the votes related to these proposals.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proposal |
|
For |
|
Against |
|
Withheld |
|
Non-Vote |
2007 Long Term |
|
|
34,677,502 |
|
|
|
10,518,784 |
|
|
|
384,743 |
|
|
|
30,964,289 |
|
Incentive Plan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Criteria |
|
|
35,477,035 |
|
|
|
9,679,178 |
|
|
|
424,817 |
|
|
|
30,964,288 |
|
for 2007 Long Term
Incentive Plan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 5. Other Information.
During the third quarter of 2007 the Company expects to enter into a Consent Decree with the United
States Environmental Protection Agency (EPA) regarding alleged violations of the Clean Water Act,
as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the Company will pay
$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 conduct certain pipeline surveys, monitoring
31
and
reporting. 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.
ITEM 6. Exhibits.
|
31.1 |
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. |
|
|
31.2 |
|
Certification of President pursuant to Rule 13a-14(a) or Rule 15d-14(a)
under the Securities Exchange Act of 1934, as amended. |
|
|
31.3 |
|
Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. |
|
|
32.1 |
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350. |
|
|
32.2 |
|
Certification of President pursuant to Rule 13a-14(b) or Rule 15d-14(b)
under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. |
|
|
32.3 |
|
Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350. |
32
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
(Registrant)
|
|
|
|
|
|
|
|
Date: August 9, 2007 |
By: |
/s/ LLOYD V. DELANO
|
|
|
|
Lloyd V. DeLano |
|
|
|
Senior Vice President
Chief Accounting Officer |
|
|
33
Exhibit Index
31.1 |
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. |
|
31.2 |
|
Certification of President pursuant to Rule 13a-14(a) or Rule 15d-14(a)
under the Securities Exchange Act of 1934, as amended. |
|
31.3 |
|
Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. |
|
32.1 |
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350. |
|
32.2 |
|
Certification of President pursuant to Rule 13a-14(b) or Rule 15d-14(b)
under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. |
|
32.3 |
|
Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or
Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350. |