e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the quarterly period ended: March 31, 2009
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 has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files.) Yes
o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company.
See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer o |
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Accelerated filer þ |
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Non-accelerated filer o
(Do not check if a smaller reporting company) |
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
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Number of shares of common stock outstanding at May 1, 2009:
93,070,592 |
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THE MERIDIAN RESOURCE CORPORATION
Quarterly Report on Form 10-Q
INDEX
2
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands of dollars, except per share information)
(unaudited)
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Three Months Ended March 31, |
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2009 |
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2008 |
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REVENUES: |
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Oil and natural gas |
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$ |
22,109 |
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$ |
38,448 |
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Price risk management activities |
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2 |
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(34 |
) |
Interest and other |
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21 |
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127 |
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22,132 |
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38,541 |
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OPERATING COSTS AND EXPENSES: |
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Oil and natural gas operating |
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4,629 |
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6,070 |
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Severance and ad valorem taxes |
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1,635 |
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2,578 |
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Depletion and depreciation |
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11,763 |
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17,742 |
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General and administrative |
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3,369 |
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4,075 |
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Accretion expense |
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523 |
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567 |
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Impairment of long-lived assets |
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59,539 |
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81,458 |
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31,032 |
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EARNINGS (LOSS) BEFORE OTHER EXPENSE &
INCOME TAXES |
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(59,326 |
) |
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7,509 |
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OTHER EXPENSE: |
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Interest expense |
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1,634 |
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1,151 |
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EARNINGS (LOSS) BEFORE INCOME TAXES |
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(60,960 |
) |
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6,358 |
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INCOME TAXES: |
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Current |
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1 |
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107 |
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Deferred |
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0 |
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2,688 |
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1 |
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2,795 |
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NET EARNINGS (LOSS) |
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$ |
(60,961 |
) |
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$ |
3,563 |
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NET EARNINGS (LOSS) PER SHARE: |
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Basic |
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$ |
(0.66 |
) |
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$ |
0.04 |
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Diluted |
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$ |
(0.66 |
) |
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$ |
0.04 |
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WEIGHTED AVERAGE NUMBER OF COMMON SHARES: |
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Basic |
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92,451 |
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89,356 |
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Diluted |
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92,451 |
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95,302 |
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See notes to consolidated financial statements.
3
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
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March 31, |
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December 31, |
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2009 |
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2008 |
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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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$ |
5,082 |
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$ |
13,354 |
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Restricted cash |
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9,968 |
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9,971 |
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Accounts receivable, less allowance for doubtful accounts of
$210 [2009 and 2008] |
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12,454 |
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16,980 |
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Prepaid expenses and other |
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863 |
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3,292 |
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Assets from price risk management activities |
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8,411 |
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8,447 |
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Total current assets |
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36,778 |
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52,044 |
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PROPERTY AND EQUIPMENT: |
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Oil and natural gas properties, full cost method (including
$30,295 [2009] and $39,927 [2008] not subject to depletion) |
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1,890,627 |
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1,877,925 |
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Land |
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48 |
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48 |
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Equipment and other |
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21,372 |
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21,371 |
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1,912,047 |
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1,899,344 |
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Less accumulated depletion and depreciation |
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1,718,798 |
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1,647,496 |
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Total property and equipment, net |
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193,249 |
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251,848 |
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OTHER ASSETS: |
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Other |
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379 |
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683 |
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Total other assets |
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379 |
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683 |
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TOTAL ASSETS |
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$ |
230,406 |
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$ |
304,575 |
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See notes to consolidated financial statements.
4
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
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March 31, |
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December 31, |
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2009 |
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2008 |
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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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$ |
7,774 |
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$ |
15,097 |
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Advances from non-operators |
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2,142 |
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5,517 |
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Revenues and royalties payable |
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5,316 |
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6,267 |
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Due to affiliates |
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8,234 |
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8,145 |
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Notes payable |
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202 |
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1,775 |
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Accrued liabilities |
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19,101 |
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18,831 |
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Liabilities from price risk management activities |
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47 |
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311 |
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Asset retirement obligations |
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353 |
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1,457 |
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Current income taxes payable |
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45 |
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47 |
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Current maturities of long-term debt |
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103,405 |
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103,849 |
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Total current liabilities |
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146,619 |
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161,296 |
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LONG-TERM DEBT |
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OTHER: |
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Asset retirement obligations |
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22,917 |
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20,768 |
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22,917 |
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20,768 |
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COMMITMENTS AND CONTINGENCIES (Note 8) |
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STOCKHOLDERS EQUITY: |
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Common stock, $0.01 par value (200,000,000 shares authorized,
93,070,592 [2009] and 93,045,592 [2008] issued)
|
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|
948 |
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|
948 |
|
Additional paid-in capital |
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538,614 |
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538,561 |
|
Accumulated deficit |
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|
(483,949 |
) |
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(422,028 |
) |
Accumulated other comprehensive income |
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8,356 |
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|
8,129 |
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|
|
|
|
|
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|
63,969 |
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|
125,610 |
|
Less treasury stock, at cost 1,712,114 [2009] and [2008]shares |
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3,099 |
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|
3,099 |
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|
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Total stockholders equity |
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|
60,870 |
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|
122,511 |
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TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
|
$ |
230,406 |
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|
$ |
304,575 |
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|
|
|
|
|
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|
See notes to consolidated financial statements.
5
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)
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Three Months Ended March 31, |
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2009 |
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2008 |
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CASH FLOWS FROM OPERATING ACTIVITIES: |
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|
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Net earnings (loss) |
|
$ |
(60,961 |
) |
|
$ |
3,563 |
|
Adjustments to reconcile net earnings (loss) to net cash
provided by operating activities: |
|
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|
|
|
|
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Depletion and depreciation |
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|
11,763 |
|
|
|
17,742 |
|
Impairment of long-lived assets |
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|
59,539 |
|
|
|
|
|
Amortization of other assets |
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304 |
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20 |
|
Non-cash compensation |
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53 |
|
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|
613 |
|
Non-cash gain on change in fair value of outstanding warrants |
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(641 |
) |
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Non-cash price risk management activities |
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|
(2 |
) |
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|
34 |
|
Accretion expense |
|
|
523 |
|
|
|
567 |
|
Deferred income taxes |
|
|
|
|
|
|
2,688 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Restricted cash |
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|
4 |
|
|
|
(1 |
) |
Accounts receivable |
|
|
3,927 |
|
|
|
(1,573 |
) |
Prepaid expenses and other |
|
|
2,429 |
|
|
|
2,609 |
|
Due to/from affiliates |
|
|
89 |
|
|
|
1,557 |
|
Accounts payable |
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|
(3,448 |
) |
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|
(442 |
) |
Advances from non-operators |
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|
(3,376 |
) |
|
|
(5,433 |
) |
Revenues and royalties payable |
|
|
(951 |
) |
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|
141 |
|
Asset retirement obligations |
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|
|
|
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|
(269 |
) |
Other assets and liabilities |
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|
(497 |
) |
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|
950 |
|
|
|
|
|
|
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Net cash provided by operating activities |
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|
8,755 |
|
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|
22,766 |
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|
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CASH FLOWS USED IN INVESTING ACTIVITIES: |
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Additions to property and equipment |
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(15,009 |
) |
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|
(38,317 |
) |
Proceeds from sale of property |
|
|
|
|
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|
4,562 |
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|
|
|
|
|
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|
Net cash used in investing activities |
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|
(15,009 |
) |
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|
(33,755 |
) |
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|
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CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: |
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|
|
|
|
|
|
|
|
|
|
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|
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Proceeds from long-term debt |
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|
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|
10,000 |
|
Reductions to long-term debt |
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|
(445 |
) |
|
|
|
|
Reductions in notes payable |
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|
(1,573 |
) |
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|
(2,447 |
) |
Additions to deferred loan costs |
|
|
|
|
|
|
(703 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(2,018 |
) |
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|
6,850 |
|
|
|
|
|
|
|
|
NET CHANGE IN CASH AND CASH EQUIVALENTS |
|
|
(8,272 |
) |
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|
(4,139 |
) |
Cash and cash equivalents at beginning of period |
|
|
13,354 |
|
|
|
13,526 |
|
|
|
|
|
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|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
5,082 |
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|
$ |
9,387 |
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|
|
|
|
|
|
|
|
Increase (decrease) of Non-cash Activities: |
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|
|
|
|
|
|
|
Accrual of capital expenditures |
|
$ |
(2,826 |
) |
|
$ |
(7,577 |
) |
ARO liability new wells drilled |
|
$ |
|
|
|
$ |
17 |
|
ARO liability changes in estimates |
|
$ |
522 |
|
|
$ |
(1,729 |
) |
See notes to consolidated financial statements.
6
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Three Months Ended March 31, 2009 and 2008
(in thousands)
(unaudited)
|
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|
|
|
|
|
|
|
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|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
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|
|
|
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|
|
|
|
|
|
|
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Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
Accumulated |
|
|
Other |
|
|
|
|
|
|
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Earnings |
|
|
Comprehensive |
|
|
Treasury Stock |
|
|
|
|
|
|
Shares |
|
|
Par Value |
|
|
Capital |
|
|
(Deficit) |
|
|
Income (Loss) |
|
|
Shares |
|
|
Cost |
|
|
Total |
|
Balance, December 31, 2007 |
|
|
89,450 |
|
|
$ |
936 |
|
|
$ |
537,145 |
|
|
$ |
(212,142 |
) |
|
$ |
(221 |
) |
|
|
159 |
|
|
$ |
(288 |
) |
|
$ |
325,430 |
|
Issuance of rights to common stock |
|
|
|
|
|
|
3 |
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Companys 401(k) plan contributions |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
(72 |
) |
|
|
133 |
|
|
|
130 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
443 |
|
Accumulated other comprehensive
loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,702 |
) |
|
|
|
|
|
|
|
|
|
|
(3,702 |
) |
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2008 |
|
|
89,450 |
|
|
$ |
939 |
|
|
$ |
537,622 |
|
|
$ |
(208,579 |
) |
|
$ |
(3,923 |
) |
|
|
87 |
|
|
$ |
(155 |
) |
|
$ |
325,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008 |
|
|
93,045 |
|
|
$ |
948 |
|
|
$ |
538,561 |
|
|
$ |
(422,028 |
) |
|
$ |
8,129 |
|
|
|
(1,712 |
) |
|
$ |
(3,099 |
) |
|
$ |
122,511 |
|
Effect of adoption of EITF Issue
07-05 (to record outstanding warrants
at fair value) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(960 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(960 |
) |
Stock-based compensation |
|
|
25 |
|
|
|
|
|
|
|
53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53 |
|
Accumulated other comprehensive
income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
227 |
|
|
|
|
|
|
|
|
|
|
|
227 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60,961 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60,961 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2009 |
|
|
93,070 |
|
|
$ |
948 |
|
|
$ |
538,614 |
|
|
$ |
(483,949 |
) |
|
$ |
8,356 |
|
|
|
(1,712 |
) |
|
$ |
(3,099 |
) |
|
$ |
60,870 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
7
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(thousands of dollars)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
Net earnings
(loss) |
|
$ |
(60,961 |
) |
|
$ |
3,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax, for
unrealized gains (losses) from hedging activities: |
|
|
|
|
|
|
|
|
Unrealized holding gains (losses) arising during period (1) |
|
|
3,798 |
|
|
|
(4,094 |
) |
Reclassification adjustments on settlement of contracts (2) |
|
|
(3,571 |
) |
|
|
392 |
|
|
|
|
|
|
|
|
|
|
|
227 |
|
|
|
(3,702 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss |
|
$ |
(60,734 |
) |
|
$ |
(139 |
) |
|
|
|
|
|
|
|
|
(1) Net income tax (expense) benefit |
|
$ |
|
|
|
$ |
2,204 |
|
(2) Net income tax (expense) benefit |
|
$ |
|
|
|
$ |
(211 |
) |
See notes to consolidated financial statements.
8
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION AND GOING CONCERN
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, 2008, as filed with the Securities and Exchange Commission
(SEC).
The financial statements included herein as of March 31, 2009, and for the three month periods
ended March 31, 2009 and 2008, 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.
As of December 31, 2008 and March 31, 2009, the Company is in default of two covenants under its
revolving credit facility. The Companys current ratio, as defined in the credit facility, was
below the required 1.0 ratio. In addition, the Company was not in compliance with a covenant
requiring that the Companys auditors opinion of its current financial statements be without
modification. The Companys 2008 audit report from its independent registered accounting firm
included a going concern explanatory paragraph that expressed substantial doubt about the
Companys ability to continue as a going concern.
Under the terms of the credit facility, the lenders have various remedies available if they choose
to declare a default, including acceleration of payment of all principal and interest. On April 13,
2009, the lenders notified the Company that, effective April 30, 2009, the borrowing base was
reduced from its current $95 million to $60 million. The credit facility provides that outstanding
borrowings in excess of the borrowing base must be repaid within 90 days after the redetermination.
The Company does not currently have sufficient cash available to repay the shortfall. The
borrowing base is determined at the discretion of the lenders, based primarily on the value of the
Companys proved reserves. The value of proved reserves has been significantly reduced during the
last several months due primarily to continuing decreases in the prices of oil and natural gas.
Management is currently in discussions with the lenders regarding alternative repayment terms,
including consideration of amortization payments from cash flow, obtaining waivers for
non-compliance with covenants creating events of default, providing additional security, and the
potential for a forbearance agreement. No assurance can be provided that the lenders will agree to
any such arrangements. Management is also considering other options for repayment, including the
sale of strategic and nonstrategic assets and obtaining capital from other sources. The Company
may not be able to sell assets on terms that management considers advantageous to the Company and
its shareholders, and capital on acceptable terms may not be available from other sources, or at
all. The Companys inability to obtain concessions from the lenders or to execute other
alternatives would have a material adverse effect on results of operations and financial condition.
9
The
Company has master derivative agreements with two of the Lenders
under the Credit Facility, which by virtue of the default under the
Credit Facility, are also in default. The counterparties under the master derivative contracts have not notified the
Company of the action they intend to pursue as a result of the event of default, if any; see Note
11 for further information.
The Company is also in default of its other bank debt, a five-year $8.4 million loan, payable in
monthly installments of approximately $196,000, which was used to purchase a drilling rig (rig
note.) Under the terms of the rig note, any non-compliance or default under the terms of the
credit facility triggers a default under the terms of the rig note, as well. The remedies available
to the lender under the rig note also include acceleration of all principal and interest payments.
The lender under the rig note was timely advised of the default under the covenants of the credit
facility and may respond with a declaration of default under the rig note. The lender may
accelerate all payments of principal and interest in response to an event of default, or may elect
to take other action.
In addition to liquidity issues related to bank debt and working capital, the Company has
significant obligations under two long term dayrate drilling rig contracts. These obligations,
described more fully in Note 8, place a significant burden on cash flow in the immediate future.
2. IMPAIRMENT OF LONG-LIVED ASSETS
At the end of each quarter, the unamortized cost of oil and natural gas properties, net of related
deferred income taxes, is limited to the sum of the estimated future after-tax net revenues from
proved properties using period-end prices, after giving effect to cash flow hedges positions,
discounted at 10%, and the lower of cost or fair value of unproved properties adjusted for related
income tax effects.
Accordingly, based on March 31, 2009 pricing of $3.76 per Mcfe of natural gas and $49.66 per barrel
of oil, the Company recognized a non-cash impairment of $59.5 million of the Companys oil and
natural gas properties under the full cost method of accounting.
Due to the substantial volatility in oil and natural gas prices and their effect on the carrying
value of the Companys proved oil and natural gas reserves, there can be no assurance that future
write-downs will not be required as a result of factors that may negatively affect the present
value of proved oil and natural gas reserves and the carrying value of oil and natural gas
properties, including volatile oil and natural gas prices, downward revisions in estimated proved
oil and natural gas reserve quantities, and unsuccessful drilling activities.
At March 31, 2009, the Company had no cushion (i.e., the excess of the ceiling over our capitalized
costs). Thus, any decrease in prices affecting the end of subsequent accounting periods, net of
the effect of hedging positions, may require the Company to record additional impairment charges.
Any future impairment would be impacted by changes in the accumulated costs of oil and natural gas
properties, which may in turn be affected by sales or acquisitions of properties and additional
capital expenditures. Future impairment would also be impacted by changes in estimated future net
revenues, which are impacted by additions and revisions to oil and natural gas reserves. A 10%
decrease in prices would have increased 2009 non-cash impairment expense by approximately $25.9
million or 44%.
Due to the redetermination of the borrowing base under the Credit Facility, the Company is
considering sales of assets to generate cash for repayment of debt. Sales of significant assets
would impact future ceiling tests, as their estimated future after-tax net revenues would be
removed from the calculation. Proceeds from sales of properties are credited to the full cost
pool, reducing the carrying value of oil and gas properties subject to the ceiling test. The
Company cannot predict whether significant property sales will cause additional ceiling test
impairments, but it is possible that they will.
10
3. SIGNIFICANT ACCOUNTING POLICIES
Drilling Rig
TMR Drilling Corporation (TMRD), a wholly owned subsidiary of the Company, owns a rig which is
used primarily to drill wells operated by the Company. In April 2008, an unaffiliated service
company, Orion Drilling, Ltd, began leasing the rig from TMRD, and operating it under a dayrate
contract with the Company. When the rig drills Company wells, drilling expenditures under the
dayrate contract are capitalized as exploration costs. All TMRD profits or losses related to lease
of the rig, including any incidental profits related to the share of drilling costs borne by our
joint interest partners, are offset against the full cost pool. SEC guidelines for full cost
accounting require this method in cases where services are performed by a company on properties
that it owns and/or manages.
When the rig is used by the service company for work on third party wells in which the Company has
no economic or management interest, TMRDs profit or loss related to the lease of the rig is
reflected in the statement of operations. During the three months ended March 31, 2009, the rig
worked entirely on third party wells, at an estimated breakeven profit to the Company.
Accordingly, no profit or loss has been recorded as income for that period.
Restricted Cash, Rabbi Trust, and Treasury Stock
The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or
usage. The restricted cash balance at December 31, 2008, was $9,971,000 and at March 31, 2009, was
$9,968,000. Restricted cash increased by $9,894,000 in May 2008, when contractual obligations to
two former executive officers were funded by cash placed in a Rabbi Trust account. Additional
restricted cash is related to a contractual obligation with respect to royalties payable.
The obligations to the former executive officers included an obligation to pay them a total of $9.9
million in cash, and 1.7 million shares of common stock of the Company, based on agreements
effective in April 2008, which terminated their employment agreements and certain other
compensation-related agreements. Both the shares and the cash from the trust will be distributed
to the former officers upon dissolution of the trust, anticipated for the second quarter of 2009.
Until distribution, the assets of the trust belong to the Company, but are effectively restricted
due to the obligation to the officers.
The shares in the trust will be accounted for as treasury shares so long as they remain in the
trust. As of March 31, 2009, the Company has no other shares in treasury.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value
Measurements (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair
value in generally accepted accounting principles and expands disclosure about fair value
measurements. The standard applies prospectively to new fair value measurements performed after the
required effective dates, which are as follows: on January 1, 2008, for the Company, the standard
became applicable to measurements of the fair values of financial instruments and recurring fair
value measurements of non-financial assets and liabilities; on January 1, 2009, for the Company,
the standard became effective for all remaining fair value measurements, including non-recurring
measurements of non-financial assets and liabilities, such as asset retirement obligations and
impairments of long-lived assets. We adopted the provisions of SFAS 157 for the fair values of
financial instruments on January 1, 2008. Beginning January 1, 2009, we applied SFAS 157 to
non-financial assets and liabilities. The adoption of SFAS No. 157 did not have a material impact
on financial position or results of operations of the Company.
11
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS 141(R) replaces SFAS
No. 141, Business Combinations. SFAS 141(R) retains the purchase method of accounting for
acquisitions, but requires a number of changes, including changes in the way assets and liabilities
are recognized in purchase accounting. It also changes the recognition of assets acquired and
liabilities assumed arising from contingencies and requires the expensing of acquisition-related
costs as incurred. Generally, SFAS 141(R) is effective on a prospective basis for all business
combinations completed on or after January 1, 2009. We adopted SFAS 141(R) as of January 1, 2009
and do not expect it to have a material impact on our financial position or results of operations,
provided we do not undertake a significant acquisition or business combination.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging
Activities, which amends FASB Statement No. 133 (SFAS 161). SFAS 161 provides guidance for
additional disclosures regarding derivative contracts, including expanded discussions of risk and
hedging strategy, as well as new tabular presentations of accounting data related to derivative
instruments. The Company adopted SFAS 161 on January 1, 2009, and the additional disclosures are
included in Note 11.
In June 2008, the FASB Emerging Issues Task Force issued EITF Abstract Issue No. 07-05,
Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entitys Own Stock
(EITF 07-05). The issue clarifies the determination of equity instruments which may qualify for
an exemption from SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.
Generally, equity instruments which qualify under the guidelines of EITF 07-05 may be accounted for
in equity accounts; those which do not qualify are subject to derivative accounting. We adopted the
guidance of EITF 07-05 on January 1, 2009. The effects of the adoption included a revision in the
carrying value of certain outstanding warrants, and recognition of a related liability on January
1, 2009, as well as recognition of an unrealized gain due to the change in fair value of those
warrants during the first quarter of 2009. See Note 9 for further information.
In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of
Oil and Gas Reporting. The new rule permits the use of new technologies to determine proved
reserves if those technologies have been demonstrated to lead to reliable conclusions about
reserves volumes. The new requirements also will allow companies to disclose their probable and
possible reserves to investors. In addition, the new disclosure requirements require companies to,
among other things: (a) report the independence and qualifications of its reserves preparer or
auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or
conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon
the prior 12-month period rather than year-end prices. The use of average prices will affect future
impairment and depletion calculations.
The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years
ending on or after December 31, 2009. A company may not apply the new rules to disclosures in
quarterly reports prior to the first annual report in which the revised disclosures are required.
The Company has not yet determined the impact of this Final Rule on its disclosures, financial
position, or results of operations; the effect of the changes will vary depending on changes in
commodity prices.
In April 2009, the FASB issued three FASB Staff Positions (FSPs) to provide additional application
guidance and enhance disclosures regarding fair value measurements and impairments of securities.
FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or
Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, provides
guidelines for making fair value measurements more consistent with the principles presented in SFAS
No. 157. FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial
Instruments, enhances consistency in financial reporting by increasing the frequency of fair value
disclosures. FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary
Impairments, provides
12
additional guidance designed to create greater clarity and consistency in accounting for and
presenting impairment losses on securities. These three FSPs are effective for interim and annual
periods ending after June 15, 2009, with early adoption permitted for periods ending after March
15, 2009. We will adopt these FSPs effective April 1, 2009 and do not anticipate the adoption
will have a material impact on financial position or results of operations of the Company.
4. FAIR VALUE MEASUREMENT
The Company adopted the provisions of SFAS 157, effective January 1, 2008. SFAS 157 does not
expand the use of fair value measurements, but rather, provides a framework for consistent
measurement of fair value for those assets and liabilities already measured at fair value under
other accounting pronouncements. Certain specific fair value measurements, such as those related
to share-based compensation, are not included in the scope of SFAS 157. Primarily, SFAS 157 is
applicable to assets and liabilities related to financial instruments, to some long-term
investments and liabilities, to initial valuations of assets and liabilities acquired in a business
combination, and to long-lived assets for which an impairment write-down to a fair value must be
made. It does not apply to oil and natural gas properties accounted for under the full cost
method, which are subject to impairment based on SEC rules. SFAS 157 applies to assets and
liabilities carried at fair value on the consolidated balance sheet, as well as to supplemental
fair value information about financial instruments not carried at fair value, which the Company
provides annually under the provisions of SFAS 107, Disclosures about Fair Value of Financial
Instruments, and will begin to provide quarterly upon adoption of FSP FAS 107-1 and APB 28-1,
"Interim Disclosures about Fair Value of Financial Instruments, effective the second quarter of
2009.
Certain provisions of SFAS 157 were deferred by the FASB. On January 1, 2009, the Company adopted
the provisions of SFAS 157 for those non-financial assets and liabilities which are measured at
fair value on a non-recurring basis. This includes new additions to asset retirement obligations,
and any long-lived assets, other than oil and natural gas properties, for which an impairment
write-down is recorded during the period. There have been no such impairments of long-lived assets
in the current period.
The Company has adopted the provisions of SFAS 157 as it applies to assets and liabilities measured
at fair value on a recurring basis on January 1, 2008. This included oil and natural gas
derivatives contracts, and as of January 1, 2009, certain outstanding warrants known as the General
Partner Warrants (see Notes 3 and 9).
SFAS 157 provides a definition of fair value and a framework for measuring fair value, as well as
expanding disclosures regarding fair value measurements. The framework requires fair value
measurement techniques to include all significant assumptions that would be made by willing
participants in a market transaction. These assumptions include certain factors not consistently
provided for previously by those companies utilizing fair value measurement; examples of such
factors would include the companys own credit standing (when valuing liabilities) and the buyers
risk premium. In adopting SFAS 157, the Company determined that the impact of these additional
assumptions on fair value measurements did not have a material effect on financial position or
results of operations.
SFAS 157 provides a hierarchy of fair value measurements, based on the inputs to the fair value
estimation process. It requires disclosure of fair values classified according to the levels
described below. The hierarchy is based on the reliability of the inputs used in estimating fair
value. The framework for fair value measurement assumes that transparent observable (Level 1)
inputs generally provide the most reliable evidence of fair value and should be used to measure
fair value whenever available. The classification of a fair value measurement is determined based
on the lowest level (with Level 3 as lowest) of significant input to the fair value estimation
process.
13
|
|
|
Level 1 fair values are based on observable inputs. Observable inputs are quoted active
market prices for assets and liabilities identical to those being valued. |
|
|
|
|
Level 2 fair values are based on observable inputs for similar assets and liabilities to
those being valued. Level 2 fair values often rely on valuation models for which the
significant inputs are observable Level 1 inputs, or inputs which can be derived from Level
1 inputs through correlation. |
|
|
|
|
Level 3 fair values are based on at least one significant unobservable input, and may
also utilize observable inputs. Unobservable inputs must be utilized when the asset or
liability being valued is not actively traded. Level 3 fair values rely on valuation
models that may utilize company-specific information or other unobservable inputs,
developed based on the best information available in the circumstances. |
The Company utilizes the modified Black-Scholes option pricing model to estimate the fair value of
oil and natural gas derivative contracts. Inputs to this model include observable inputs from the
New York Mercantile Exchange (NYMEX) for futures contracts, and inputs derived from NYMEX
observable inputs, such as implied volatility of oil and gas prices. The Company has classified
the fair values of all its derivative contracts as Level 2.
The fair value of the Companys general partner warrants (see Notes 3 and 9) were valued using the
Black-Scholes option pricing model.
Assets and liabilities measured at fair value on a recurring basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2009 |
|
|
|
|
|
|
|
|
|
|
Using (thousands of dollars) |
|
|
|
|
|
|
|
|
|
|
Quoted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Active |
|
Significant |
|
Significant |
|
|
|
|
|
|
|
|
|
|
Markets for |
|
Other |
|
Other |
|
|
|
|
|
|
|
|
|
|
Identical |
|
Observable |
|
Unobservable |
|
|
|
|
|
|
March |
|
Assets |
|
Inputs |
|
Inputs |
Description |
|
|
|
|
|
31, 2009 |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
Assets from price risk
management activities |
|
|
(1) |
|
|
$ |
8,411 |
|
|
|
|
|
|
$ |
8,411 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities from price
risk management
activities |
|
|
(1) |
|
|
$ |
47 |
|
|
|
|
|
|
$ |
47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner warrants |
|
|
(2) |
|
|
$ |
320 |
|
|
|
|
|
|
$ |
320 |
|
|
|
|
|
|
|
|
(1) |
|
Assets and liabilities from price risk management activities are oil and natural gas
derivative contracts, in the form costless collars to sell oil and natural gas within specific
future time periods. These contracts are more fully described in Note 11. |
|
(2) |
|
General partner warrants are more fully described in Note 9. |
14
As noted above, FAS 157 also applies to new additions to asset retirement obligations, which must
be estimated at fair value when added. New additions may result from increases to estimations of
existing obligations or from estimations for new obligations for new properties, and fair values
for them would be categorized as Level 3. Such estimations are based on present value techniques
which utilize company-specific information. There were no new asset retirement obligations
measured at fair value during the three months ended March 31, 2009.
5. ACCRUED LIABILITIES
Below is the detail of accrued liabilities on the Companys balance sheets as of March 31, 2009 and
December 31, 2008 (thousands of dollars):
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Capital expenditures |
|
$ |
8,672 |
|
|
$ |
8,227 |
|
Operating expenses/taxes |
|
|
3,763 |
|
|
|
4,452 |
|
Hurricane damage repairs |
|
|
919 |
|
|
|
1,555 |
|
Compensation |
|
|
3,389 |
|
|
|
2,478 |
|
Interest |
|
|
378 |
|
|
|
261 |
|
General partner warrants |
|
|
320 |
|
|
|
|
|
Other |
|
|
1,660 |
|
|
|
1,858 |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
19,101 |
|
|
$ |
18,831 |
|
|
|
|
|
|
|
|
6. DEBT
Credit Facility. On December 23, 2004, the Company amended its credit facility to provide for a
four-year $200 million senior secured credit facility (the Credit Facility) with Fortis Capital
Corp., as administrative agent, sole lead arranger and bookrunner; Comerica Bank as syndication
agent; and Union Bank of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
PLC, RZB Finance LLC and Standards Bank PLC completed the syndication group. The initial borrowing
base under the Credit Facility was $130 million. The borrowing base under the Credit Facility was
redetermined by the syndication group to be $115 million effective October 31, 2007.
On February 21, 2008, the Company amended the Credit Facility. The lending institutions under the
amended Credit Facility include Fortis Capital Corp. as administrative agent, co-lead arranger and
bookrunner; The Bank of Nova Scotia, as co-lead arranger and syndication agent; Comerica Bank, US
Bank NA and Allied Irish Bank plc each in their respective capacities as lenders (collectively, the
Lenders.) The maturity date was extended to February 21, 2012, and the borrowing base was
redetermined to be $110 million. Interest rates were slightly increased by increasing the range of
the add-on to the prime base rate by 250 basis points on the lower end of the range and by 500
basis points on the higher end of the range; the range of the add-on to the alternative base rate
was increased by 250 basis points on the higher end of the range.
On December 19, 2008, the Company entered into the Second Amendment to Credit Agreement to the
Credit Facility (Second Amendment). The Second Amendment redetermined the borrowing base at $95
million, limiting borrowing to the amount outstanding at December 31, 2008. In addition, interest
rates were increased by increasing the range of the add-on to the prime base rate by 500 basis
points on the lower end of the range and by 750 basis points on the higher end of the range; the
range of the add-on to the alternative base rate was increased by the same amounts.
The terms of the Credit Facility contain numerous covenants and restrictions. Currently, the
Company is
15
in default of a covenant which requires that it maintain a current ratio (as defined in
the Credit Facility) of one to one. The current ratio, as defined, was less than the required one
to one at both December 31, 2008 and March 31, 2009. The Company is also in default of the
requirement that the Companys auditors opinion for the current financial statements be without
modification. The Companys 2008 audit report from its independent registered accounting firm
included a going concern explanatory paragraph that expressed substantial doubt about the
Companys ability to continue as a going concern. As a result of the default, the outstanding
Credit Facility balance of $95 million at December 31, 2008 and March 31,
2009 has been classified in current liabilities on the accompanying consolidated balance sheets.
The Lenders were informed of the defaults under the covenants. Under the terms of the Credit
Facility, the Lenders have various remedies available in the event of a default, including
acceleration of payment of all principal and interest. On April 13, 2009, the Lenders notified the
Company that, effective April 30, 2009, the borrowing base was reduced from its current $95 million
to $60 million. The Credit Facility provides that outstanding borrowings in excess of the
borrowing base must be repaid within 90 days after the redetermination. The Company does not
currently have sufficient cash available to repay the shortfall. The borrowing base is determined
at the discretion of the Lenders, based primarily on the value of the Companys proved reserves.
The value of proved reserves has been significantly reduced during the last several months due
primarily to continuing decreases in the prices of oil and natural gas. Management is currently in
discussions with the Lenders regarding repayment terms, including consideration of amortization
payments from cash flow, obtaining waivers for non-compliance with covenants creating events of
default, providing additional security, and the potential for a forbearance agreement. No
assurance can be provided that the Lenders will agree to any such arrangements. Management is also
considering other options for repayment, including the sale of strategic and nonstrategic assets
and obtaining capital from other sources. The Company may not be able to sell assets on terms that
management considers advantageous to the Company and its shareholders, and capital on acceptable
terms may not be available from other sources, or at all. The Companys inability to obtain
concessions from the Lenders or to execute other alternatives would have a material adverse effect
on results of operations and financial condition.
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 Lenders can redetermine the borrowing
base to a lower level than the current borrowing base if they determine that the Companys oil and
natural gas reserves, at the time of redetermination, are inadequate to support the borrowing base
then in effect. In the event the redetermined borrowing base is less than outstanding borrowings
under the Credit Facility, the Company will be required to repay the deficit within a 90-day
period.
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 repurchases of
common stock, restrictions on incurrence of additional debt, and an unqualified audit report on the
Companys consolidated financial statements. As noted above, at December 31, 2008 and March 31,
2009, the Company was in default of two of these covenants.
16
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 1.25% to 2.50% 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 2.0% to 3.25%, depending on the ratio of the aggregate
outstanding loans and letters of credit to the
borrowing base. At December 31, 2008, the three-month LIBOR interest rate was 1.425%; at March 31,
2009 it was 1.19%, and the prime rate remained at 3.25%. During the first quarter of 2009, the
Lenders informed the Company that all outstanding tranches of debt would be converted to
prime-based from LIBOR-based upon maturity. The Credit Facility continues to provide for
commitment fees of 0.375% calculated on the difference between the borrowing base and the aggregate
outstanding loans and letters of credit under the agreements. As of May 1, 2009, outstanding
borrowing under the Credit Facility totaled $95.0 million.
Rig Note. On May 2, 2008, the Company, through its wholly owned subsidiary TMR Drilling Corporation
(TMRD), entered into a financing agreement with The CIT Group Equipment Financing, Inc. (CIT).
Under the terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625%,
in order to refinance the purchase of a land-based drilling rig to be used in Company operations.
The rig had been purchased using cash on hand and funds available to the Company under the Credit
Facility. Funds from the new agreement were used to reduce borrowing under the Credit Facility. The
loan is collateralized by the drilling rig, as well as general corporate credit. The term of the
loan is five years; monthly payments of $196,248 for interest and principal are to be made until
the loan is completely repaid at termination of the agreement on May 2, 2013.
Effective as of December 31, 2008, the Companys defaults under the Credit Facility also resulted
in an event of default under the rig note. The remedies available to CIT in the event of default
include acceleration of all principal and interest payments. All indebtedness under the rig note,
$8.8 million at December 31, 2008 and $8.4 million at March 31, 2009, has been classified in
current liabilities on the accompanying consolidated balance sheets as of December 31, 2008 and
March 31, 2009.
CIT was notified of the Companys defaults under the covenants of the Credit Facility, and has not
responded with a notice of any remedies it may choose to pursue.
7. INCOME TAXES
The Companys effective income tax rate has varied significantly in recent periods. In the first
quarter of 2008, our effective income tax rate was 44%, which is higher than the corporate income
tax rate of 35% primarily due to state taxes and other permanent differences. In the fourth
quarter of 2008 and the first quarter of 2009, we recorded significant non-cash impairment losses
(see Note 2). Generally Accepted Accounting Principles require a valuation allowance to be
recognized if, based on the weight of available evidence, it is more likely than not that some
portion or all of the deferred tax asset will not be realized. The Company does not expect to
realize its deferred tax assets, and therefore recorded a valuation allowance in 2008 to the full
extent of all net deferred tax assets. The allowance was adjusted in the first quarter of 2009 to
maintain this complete offset of all deferred tax assets. Thus, the tax benefit related to net
losses recognized in the first quarter was zero, and the effective tax rate for that period is 0%.
In the fourth quarter of 2008, we were notified by the Internal Revenue Service that Meridian would
be audited for fiscal years 2006 and 2007. The audit is near completion and the Company does not
expect a material impact on financial position or results of operations.
17
8. COMMITMENTS AND CONTINGENCIES
Litigation
H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for damages estimated to exceed several million dollars for Meridians alleged gross
negligence, willful misconduct and breach of fiduciary duty under certain agreements concerning
certain wells and property
in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of
Meridians satisfying a prior adverse judgment in favor of Amoco Production Company. Mr. James Bond
had been added as a defendant by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins,
did not have the right to consent, could not consent or breached his fiduciary duty to Hawkins if
he did consent to all actions taken by Meridian. Mr. James T. Bond was employed by H.L. Hawkins Jr.
and his companies as General Manager until 2002. He served on the Board of Directors of the Company
from March 1997 to August 2004. After Mr. Bonds employment with Mr. Hawkins, Jr., and his
companies ended, Mr. Bond was engaged by The Meridian Resource & Exploration LLC as a consultant.
This relationship continued until his death. Mr. Bond was also the father-in-law of Michael J.
Mayell, the Chief Operating Officer of the Company at the time. A hearing was held before Judge Kay
Bates on April 14, 2008. Judge Bates granted Hawkins Motion finding that Meridian was estopped
from arguing that it did not breach its contract with Hawkins as a result of the United States
Fifth Circuits decision in the Amoco litigation. Meridian disagrees with Judge Bates ruling but
the Louisiana First Court of Appeal declined to hear Meridians writ requesting the court overturn
Judge Bates ruling. Meridian filed a motion with Judge Bates
asking that the ruling be made a
final judgment which would give Meridian the right to appeal
immediately; however, the Judge declined to grant the motion, allowing the case to proceed to trial. Management continues to vigorously defend
this action on the basis that Mr. Hawkins individually and through his agent, Mr. Bond, agreed to
the course of action adopted by Meridian and further that Meridians actions were not grossly
negligent, but were within the business judgment rule. Since Mr. Bonds death, a pleading has been
filed substituting the proper party for Mr. Bond. The Company is unable to express an opinion with
respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or
range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided
any amount for this matter in its financial statements at March 31, 2009.
Parsons Exploration litigation. On May 3, 2007, Parsons Exploration Company, LLC (Parsons) filed
a claim against Meridian for damages and specific performance requiring Meridian to assign Parsons
an overriding royalty interest in certain wells the Company has drilled in east Texas. The
complaint alleged that the Company breached its contractual and fiduciary obligations to Parsons
under an Exploration and Prospect Origination Agreement between the parties dated April 22, 2003.
The complaint also alleged that the Company engaged in a civil conspiracy to breach its contractual
and fiduciary obligations to Parsons and tortiously interfered with existing and prospective
business relationships/contracts of Parsons. The Company has recognized an estimated settlement for
this matter in the amount of $2.1 million, which was charged to the full cost pool in the first
quarter of 2009.
Environmental litigation. Various landowners have sued Meridian (along with numerous other oil
companies) in lawsuits concerning several fields in which the Company has had operations. The
lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to restore the
plaintiffs lands from alleged contamination and otherwise from the Companys oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP (together, Shell) have
demanded contractual indemnity and defense from Meridian based upon the terms of the acquisition
agreements related to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded
contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement
related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some
cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the
fields. On December 9, 2008 Shell sent Meridian a letter reiterating its
18
demand for indemnity.
Shell has not to date produced all of the supporting documentation for its claim. In the Companys
discussions with Shell, Shell has indicated that it is considering filing an arbitration, but has
not yet initiated a formal proceeding. Meridian denies that it owes any indemnity under the
acquisition agreements; however, the amounts claimed are substantial in nature and if adversely
determined, would have a material adverse effect on the Company. The Company is unable to express
an opinion with respect to the likelihood of an unfavorable outcome of these matters or to estimate
the amount or range of potential loss should any outcome be unfavorable. Therefore, the Company has
not
provided any amount for these matters in its financial statements at March 31, 2009.
Title/lease disputes. Title and lease disputes may arise in the normal course of the Companys
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Litigation involving insurable issues. There are no material legal proceedings involving insurable
issues which exceed insurance limits to which Meridian or any of its subsidiaries is a party or to
which any of its property is subject, other than ordinary and routine litigation incidental to the
business of producing and exploring for crude oil and natural gas.
Other contingencies
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
after-tax 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. This is known as the ceiling test. The
Company recorded significant impairment charges against oil and gas properties based on the results
of the ceiling test in the fourth quarter of 2008 and again in the first quarter of 2009.
At March 31, 2009, the Company had no cushion (i.e., the excess of the ceiling over capitalized
costs). Thus, any decrease in prices affecting the end of subsequent accounting periods, net of
the effect of the Companys hedging positions, may necessitate additional impairment charges. Any
future impairment would be impacted by changes in the accumulated costs of oil and natural gas
properties, which may in turn be affected by sales or acquisitions of properties and additional
capital expenditures. Future impairment would also be impacted by changes in estimated future net
revenues, which are impacted by additions and revisions to oil and natural gas reserves, as well as
by sales and acquisitions of properties. A 10% decrease in prices would have increased our 2009
non-cash impairment expense by approximately $25.9 million or 44%.
Due to the redetermination of the borrowing base under the Credit Facility, the Company is
considering sales of assets to generate cash for repayment of debt. Sales of significant assets
would impact future ceiling tests, as their estimated future after-tax net revenues would be
removed from the calculation. Proceeds from sales of properties are credited to the full cost
pool, reducing the carrying value of oil and gas properties subject to the ceiling test. The
Company cannot predict whether significant property sales will cause additional ceiling test
impairments, but it is possible that they will.
Hurricane damages. Certain oil and natural gas properties sustained physical damage during two
hurricanes in the third quarter of 2008, hurricane Gustav and hurricane Ike. The accompanying
balance sheet includes a $2.4 million insurance receivable at March 31, 2009, based on the most
current information available. Damage estimates for non-operated properties are subject to
revision. Also, additional information regarding non-operated properties may be obtained which
bears on the applicability of insurance deductibles, and may also require revision to loss
estimates.
19
Drilling rigs. The Company has significant contractual obligations for the use of two drilling
rigs. The Companys capital expenditure plans no longer include full use of these rigs; however,
the Company is obligated for the dayrate regardless of whether the rigs are working or idle. When
either rig is not in use on Meridian-operated wells, the operator may contract it to third parties,
or the rig may be idled. The operator has been cooperative in actively seeking other parties to use
the rigs, and in agreeing to credit the Companys obligation to some extent, based on revenues from
other parties who utilize the rig(s) when the Company is unable to. The rigs were used continuously
by the Company through approximately the
end of 2008. During the first quarter of 2009, one rig has been effectively subleased to others,
but for short duration, at rates less than the dayrate under the Companys contract. The Company is
obligated for the difference in dayrates. However, this is the rig owned by the Company and any
profits from its use by the operator are shared with the Company, such that for the first quarter
of 2009, the dayrate shortfall is estimated to have been offset by the Company share of rig
operations profit and no loss has been recognized. The other rig continued to be utilized drilling
a Meridian-operated well through the end of the quarter, although it has subsequently been released
by Meridian, and is currently under short-term contract to a third party. Management cannot predict
whether such use by third parties will be consistent, nor to what extent it may offset obligations
under the dayrate contract. The Company has not provided any amount for these matters in its
financial statements at March 31, 2009. Expenditures for the rigs when they are not drilling for
the Company are expected to be expensed as they occur.
9. STOCKHOLDERS EQUITY
Common Stock
In March 2007, the Companys Board of Directors authorized a share repurchase program. Under the
program, the Company may repurchase in the open market or through privately negotiated transactions
up to $5 million worth of common shares per year over three years. The timing, volume, and nature
of share repurchases will be at the discretion of management, depending on market conditions,
applicable securities laws, and other factors. Prior to implementing this program, the Company was
required to seek approval of the repurchase program from the Lenders under the Credit Facility. The
repurchase program was approved by the Lenders, subject to certain restrictive covenants. During
February 2007, the Lenders in the Credit Facility unanimously approved an amendment increasing the
available limit for the Companys repurchase of its common stock from $1.0 million to $5.0 million
annually. The amendment contained restrictive covenants on the Companys ability to repurchase its
common stock including (i) the Company cannot utilize funds under the Credit Facility to fund any
stock repurchases and (ii) immediately prior to any repurchase, availability under the Credit
Facility must be equal to at least 20% of the then effective borrowing base. From March 2007, the
inception of the share repurchase program, through March 31, 2009, the Company had repurchased
535,416 common shares at a cost of $1,234,000, of which 501,300 shares have been reissued for
401(k) contributions, for contract services and for compensation, and 34,116 have been retired. The
program does not require the Company to repurchase any specific number of shares and may be
modified, suspended, or terminated at any time without prior notice. The Company does not expect
to make share repurchases in the near term.
General Partner Warrants
As of December 31, 2008, the Company had outstanding warrants (the General Partner Warrants) that
entitle Joseph A. Reeves, Jr. and Michael J. Mayell to purchase an aggregate of 1,884,544 shares of
common stock at an exercise price of $0.10 per share through December 31, 2015. The number of
shares of common stock purchasable upon the exercise of each warrant and its corresponding exercise
price are subject to various anti-dilution adjustments. Messrs. Reeves and Mayell, respectively,
are the former Chief Executive Officer and former Chief Operating Officer of the Company.
20
In June 2008, the FASB Emerging Issues Task Force issued EITF Abstract Issue No. 07-05,
Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entitys Own Stock
(EITF 07-05). The issue clarifies the determination of equity instruments which may qualify for
an exemption from SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS
133). Generally, equity instruments which qualify under the guidelines of EITF 07-05 may be
accounted for in equity accounts; those which do not qualify are subject to derivative accounting.
The Company adopted EITF 07-05 on January 1, 2009. Its provisions were considered in regard to the
General Partner Warrants and it was determined that they were not indexed to the Companys own
stock. Accordingly, a charge of $960,000 was recorded on January 1, 2009 to retained earnings to
reflect the cumulative effect of recording the 1,884,544 warrants at fair value, with an offsetting
entry to accrued liabilities. Adjustments to fair value are being made on a prospective basis,
beginning in 2009. For the three months ended March 31, 2009, the Company recorded a gain on the
valuation of the warrants of $641,000, which is included in General and Administrative Expense.
In addition to customary anti-dilution adjustments, the number of shares of common stock and the
exercise price per share of the General Partner Warrants are subject to adjustment for any issuance
of common stock by the Company such that each warrant will permit the holder to purchase at the
same aggregate exercise price, a number of shares of common stock equal to the percentage of
outstanding shares of common stock that the holder could purchase before the issuance.
There were 1,885,052 General Partner Warrants outstanding at March 31, 2009, included in accrued
liabilities at a total fair value of $320,000. Fair value is based on the Black-Scholes model for
option pricing.
10. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted net earnings (loss) per share
(in thousands, except per share):
21
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
Numerator: |
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
$ |
(60,961 |
) |
|
$ |
3,563 |
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Denominator for basic earnings per
share weighted-average shares outstanding |
|
|
92,451 |
|
|
|
89,356 |
|
Effect of potentially dilutive common shares: |
|
|
|
|
|
|
|
|
Warrants and stock rights (a) |
|
NA |
|
|
|
5,946 |
|
Employee and director stock options (a) |
|
NA |
|
|
NA |
|
|
|
|
|
|
|
|
Denominator for diluted earnings per share
weighted-average shares outstanding
and assumed conversions |
|
|
92,451 |
|
|
|
95,302 |
|
|
|
|
|
|
|
|
Basic earnings (loss) per share |
|
$ |
(0.66 |
) |
|
$ |
0.04 |
|
|
|
|
|
|
|
|
Diluted earnings (loss) per share |
|
$ |
(0.66 |
) |
|
$ |
0.04 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The number of warrants excluded for the three months ended March 31, 2009 totaled
approximately 3.3 million. The number of options excluded for that period totaled approximately
0.7 million. A total of 3.4 million options were excluded for the three months ended March 31,
2008, because the options exercise price was greater than the average market price of the common
shares, which made them anti-dilutive. |
Warrants and stock options for which the exercise prices were greater than the average market price
of the Companys common stock are excluded from the computation of diluted earnings per share.
Stock rights issued under our deferred compensation plan, which had all been converted and were no
longer outstanding during the first quarter of 2009, had no exercise price and are included in
diluted earnings per share for the three months ended March 31, 2008. All potentially dilutive
shares, whether from options, warrants, or rights, are excluded when there is an operating loss,
because inclusion of such shares would be anti-dilutive.
11. RISK MANAGEMENT ACTIVITIES
Management of Financial Risk
The Companys operating environment includes two primary financial risks which could be addressed
through derivatives and similar financial instruments: the risk of movement in oil and natural gas
commodity prices, which impacts revenue, and the risk of interest rate movements, which impacts
interest expense from floating rate debt.
The Company currently does not utilize derivative contracts or any other form of hedging against
interest rate risk.
The Company utilizes derivative contracts to address the risk of adverse oil and natural gas
commodity price fluctuations. While the use of derivative contracts limits the downside risk of
adverse price movements, it may also limit future gains from favorable movements. No derivative
contracts have been entered into for trading purposes, and the Company has the intent to hold each
instrument to maturity. The Companys commodity derivative contracts are considered cash flow
hedges under SFAS 133.
22
Oil and Natural Gas Hedging Contracts
The Company has historically utilized derivative contracts to hedge the sale of a portion of its
future production. The Companys objective is to reduce the impact of commodity price fluctuations
on both income and cash flow, as well as to protect future revenues from adverse price movements.
Management considers some exposure to market pricing to be desirable, due to the potential for
favorable price movements, but prefers to achieve a measure of stability and predictability over
revenues and cash flows by hedging some portion of production. The Companys commodity derivative
positions as of March 31, 2009 hedge approximately 29% of proved developed natural gas production
and 16% of proved developed oil production during the remaining terms of all derivative agreements
in the aggregate.
The Company has historically chosen derivative contracts in the form of costless collars. These
agreements ensure the Company receives a minimum (floor) price for the commodity, while
concurrently limiting the price to a specified maximum (ceiling). Typically, the contracts specify
monthly hedged volumes subject to the floor and ceiling prices over a period of 6 to 18 months.
The contracts are settled monthly based on the NYMEX futures contract. Counter-parties to these
contracts are large financial institutions that are members of the lending group which is party to
our Credit Facility. The following table lists all of the Companys commodity derivative contracts
as of March 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Price |
|
|
March 31, 2009 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
860,000 |
|
|
$ |
7.50 |
|
|
$ |
10.45 |
|
|
$ |
2,866 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
530,000 |
|
|
$ |
8.00 |
|
|
$ |
10.30 |
|
|
|
2,012 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
360,000 |
|
|
$ |
8.00 |
|
|
$ |
13.35 |
|
|
|
1,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas |
|
|
6,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
17,000 |
|
|
$ |
70.00 |
|
|
$ |
93.55 |
|
|
|
298 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
28,000 |
|
|
$ |
80.00 |
|
|
$ |
111.00 |
|
|
|
751 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
34,000 |
|
|
$ |
85.00 |
|
|
$ |
128.50 |
|
|
|
1,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil |
|
|
2,119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
8,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounting and financial statement presentation for derivatives
The Company accounts for its derivative contracts under the provisions of SFAS 133. Under SFAS
133, the Companys commodity derivatives are designated as cash-flow hedges and are stated at fair
value on the Consolidated Balance Sheets. See Note 4, Fair Value Measurements for further
information on how fair values of derivative instruments are determined. Changes in fair value,
which occur due to commodity price movements, are offset in Other Comprehensive Income. When the
derivative contract or a portion of it matures, the gain or loss is settled in cash and
reclassified from Accumulated Other Comprehensive Income to Revenues from Oil and Natural Gas. Net
settlements under hedging agreements increased (decreased) oil and natural gas revenues by
$3,571,000 and ($603,000) for the three months ended March 31, 2009 and 2008, respectively. A gain
or loss may be recorded to earnings prior
23
to contract maturity if a portion of the cash flow hedge
becomes ineffective under the guidelines provided by SFAS 133 and related interpretations, or if
the forecasted transaction is no longer expected to occur. Although the Company periodically
records gains or losses from hedge ineffectiveness, there have been no losses recorded due to
cancellations or changes in expectations regarding occurrence of the hedged transactions. The
following two tables provide information regarding assets, liabilities, gains, and losses related
to derivative contracts, and where these amounts are reflected within the Companys financial
statements (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Contracts at |
Description and location within |
|
|
|
|
|
December 31, |
Consolidated Balance Sheet |
|
March 31, 2009 |
|
2008 |
Derivative contracts
designated as
hedging instruments
under SFAS 133 |
|
|
|
|
|
|
|
|
Commodities Contracts |
|
|
|
|
|
|
|
|
Current assets from
price risk
management
activities |
|
$ |
8,411 |
|
|
$ |
8,447 |
|
|
|
|
|
|
|
|
|
|
Non-current assets
from price risk
management
activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
from price risk
management
activities |
|
$ |
47 |
|
|
$ |
311 |
|
|
|
|
|
|
|
|
|
|
Non-current
liabilities from
price risk
management
activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts
not designated as
hedging instruments
under SFAS 133 |
|
NONE |
|
NONE |
24
Effect of Derivative Contracts on the
Consolidated Balance Sheets and the Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended |
|
|
Location of Gain |
|
|
|
|
|
|
(Loss) within |
|
March 31, |
|
March 31, |
Description |
|
Financial Statements |
|
2009 |
|
2008 |
|
Derivative contracts
designated as cash
flow hedging
instruments: |
|
|
|
|
|
|
|
|
|
|
Gain (loss) on
derivative contracts
recognized in Other
Comprehensive Income
(OCI) |
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Accumulated Other
Comprehensive Income
|
|
|
3,798 |
|
|
|
(6,298 |
) |
|
Gain (loss) on
derivative contracts
reclassified from
OCI to earnings
|
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Oil and Natural Gas Revenues
|
|
|
3,571 |
|
|
|
(603 |
) |
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) due to
hedging
ineffectiveness
reported in earnings
|
|
|
|
|
|
|
|
|
|
|
Commodities Contracts
|
|
Revenues from Price Risk
Management Activities
|
|
|
2 |
|
|
|
(34 |
) |
|
|
|
|
|
|
|
|
|
|
|
Fair value of
derivative contracts
designated as cash
flow hedging
instruments,
excluded from
effectiveness
assessments
|
|
|
|
NONE
|
|
NONE
|
|
|
|
|
|
|
|
|
|
|
|
Derivative contracts
not designated as
hedging instruments
|
|
|
|
NONE
|
|
NONE
|
As of March 31, 2009, the Company had an unrealized gain of $8.4 million (pre-tax and net of tax)
deferred in Accumulated Other Comprehensive Income. Based upon oil and natural gas commodity
25
prices at March 31, 2009, all of the unrealized gain deferred in Accumulated Other Comprehensive
Income could potentially increase gross revenues in the next nine months. These derivative
agreements expire December 31, 2009.
Special terms in derivative contracts
Although the Companys counterparties provide no collateral, the master derivative agreements
with each counterparty effectively allow the Company, at its option, so long as it is not a
defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid
hedging agreement receivable against the interest of the counterparty in any outstanding balance
under the Credit Facility. In practice, no such set-off has been made, and all settlements have
been made in cash. As of December 31, 2008 and continuing at March 31, 2009, however, the Company
is in default of two covenants contained in the Credit Facility, the breach of which is also a
default under the master derivative agreements. Although the Companys hedge counterparties have
continued to make contract payments subsequent to its default, they are not obligated to make
payments to the Company under the hedging agreements while the Companys default is continuing. The
Companys set-off rights under the master derivative agreements cannot be exercised due to such
default. The Companys hedging counterparties may exercise their remedies under the hedging
agreements, and potentially under the Credit Facility, on account of the Companys default, which
includes a right to set-off any amount due to the Company under the derivative
agreements against amounts owed to that counterparty as a Lender under the Credit Facility.
If a counterparty were to default in payment of an obligation under the master derivative
agreements, the Company would be exposed to commodity price fluctuations, and the protection
intended by the hedge would be lost. The value of assets from price risk management would be
impacted. In addition, as expected cash flows from hedging contracts are included in computing
future net revenues, the ceiling test could be impacted, which could result in a non-cash
write-down of oil and natural gas properties.
12. SHARE-BASED COMPENSATION
Stock Options
The Company records share-based compensation expense under the provisions of SFAS No. 123R,
Share-Based Payment. Compensation expense is based on the fair value of the share-based award
determined at grant date and recognized over the service period, which is generally the vesting
period of the award. Share-based compensation expense of approximately $53,000 was recorded in the
three months ended March 31, 2009 and $613,000 was recognized in the three month period ended March
31, 2008. Compensation paid in share-based awards included stock options and non-vested shares
granted to our employees and directors and stock rights awarded under our deferred compensation
plan for certain executives, which was discontinued after April 2008.
13. ASSET RETIREMENT OBLIGATIONS
The Company estimates the present value of future costs of dismantlement and abandonment of its
wells, facilities, and other tangible long-lived assets, recording them as liabilities in the
period incurred. Asset retirement obligations are calculated using an expected present value
technique. Salvage values are excluded from the estimation.
When the liability is initially recorded, the entity increases the carrying amount of the related
long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost
is amortized over the
26
useful life of the related asset. Upon settlement of the liability, the
Company incurs a gain or loss based upon the difference between the estimated and final liability
amounts. The Company records gains or losses from settlements as adjustments to the full cost pool.
The following table describes the change in the Companys asset retirement obligations for the
three months ended March 31, 2009, (thousands of dollars):
|
|
|
|
|
Asset retirement obligation at December 31, 2008 |
|
$ |
22,225 |
|
Additional retirement obligations recorded in 2009 |
|
|
|
|
Settlements during 2009 |
|
|
|
|
Revisions to estimates and other changes during 2009 |
|
|
522 |
|
Accretion expense for 2009 |
|
|
523 |
|
|
|
|
|
Asset retirement obligation at March 31, 2009 |
|
|
23,270 |
|
Less: current portion |
|
|
353 |
|
|
|
|
|
Asset retirement, long-term, at March 31, 2009 |
|
$ |
22,917 |
|
|
|
|
|
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
Operations Update
Production volumes for the first quarter of 2009 totaled 3.3 billion cubic feet of gas equivalent
(Bcfe), or an average of 37.1 million cubic feet of natural gas equivalent per day (Mmcfe/d)
compared to 3.7 Bcfe or 41.0 Mmcfe per day for the first quarter of 2008. The variance in
production volumes between the two periods is due to natural production declines, offset in large
part by new discoveries brought online since the first quarter of 2008. New discoveries affecting
production between the periods include those in East Texas, Weeks Island, Ramos and Turtle Bayou.
Currently, the overall average daily production for the Company ranges between 35 and 38 Mmcfe per
day.
During the first quarter, Meridian completed the Goodrich-Cocke No. 7 in Weeks Island (tested at
900 Boe/d, 430 net) and the Myles Salt No. 27 in Weeks Island (tested at 770 Boe/d, 455 net).
Construction on the previously announced Weeks Bay No. 15 well pipeline and production facility
tie-in is substantially complete and the well will be turned over to production in the coming days.
In late April 2009, the outside operated Davis A-39 well was tested at a gross daily rate as high as
20 Mmcfe per day (3.5 net). In the first week of production this well has averaged approximately
17.9 Mmcfe per day. The Company expects that the well will display similar producing
characteristics to other Austin Chalk wells in the area, with the typical hyperbolic decline curve
from current production levels during the coming months. Additional work was conducted on the Black
Stone Minerals No. A-278 well in East Texas resulting in minimal improvement, and the well is
currently considered to be uneconomic.
Capital Expenditure Plans for 2009
The Company anticipates the 2009 capital spending budget will be primarily used for recompletions
and similar work on existing properties, and for lease maintenance costs. We anticipate that the
budget will be significantly lower than in past years, reflecting our expectations of reduced cash
flows due to
27
commodity price declines and the loss of availability of funds under the Credit
Facility. These factors will significantly impact funds available for capital spending. We
currently anticipate funding the 2009 plan utilizing cash flow from operations and cash on hand,
augmented by proceeds from sales of assets as possible.
Other Conditions
Industry and Economic Conditions. Revenues, profitability and future growth rates of Meridian are
substantially dependent upon prevailing prices for oil and natural gas. Oil and natural gas prices
have been extremely volatile in recent years and are affected by many factors outside of our
control. Our average oil price (after adjustments for hedging activities) for the three months
ended March 31, 2009, was $45.62 per barrel compared to $86.91 per barrel for the three months
ended March 31, 2008, and $53.47 per barrel for the three months ended December 31, 2008. Our
average natural gas price (after adjustments for hedging activities) for the three months ended
March 31, 2009, was $6.07 per Mcf compared to $8.55 per Mcf for the three months ended March 31,
2008, and $6.85 per Mcf for the three months ended December 31, 2008.
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 impacts our revenues,
profitability and ability to maintain or increase our exploration and development program. Pricing
also significantly impacts our future net revenue from oil and natural gas, which impacts the
ceiling test and related impairment expense. Refer to Item 3, Quantitative and Qualitative
Disclosures about Market Risk, for information regarding commodity price risk management activities
utilized to mitigate a portion of the near term effects of this exposure to price volatility.
Global capital markets have experienced significant disruptions in the past year, resulting in the
closing or restructuring of numerous large financial institutions. Extreme uncertainty about
creditworthiness, liquidity and interest rates, as well as the global economic recession, continue
to limit credit availability. In addition, the market value of the Companys reserves has
decreased, both in the fourth quarter of 2008 and in the first quarter of 2009, due primarily to
energy price fluctuations. Our access to credit has significantly declined.
The decrease in oil and natural gas prices has also caused operating cash flows to decline across
the industry and at Meridian.
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, 2008, for further discussion.
The
Company adopted Emerging Issues Task Force Issue 07-05 effective
January 1, 2009. The adoption requires us to value certain
outstanding warrants for our common stock, known as the General
Partner Warrants, at fair value at each reporting date. As the fair
value changes, the difference from period to period is recognized in
the consolidated statement of operations. The fair value is based on
the Black-Scholes model for option pricing, and varies from period to
period primarily due to fluctuation in the market price of our common
stock. Upon adoption, we recorded a charge of $960,000 to retained
earnings to reflect the cumulative effect of recording the
1.9 million warrants at fair value on January 1, 2009, with
an offsetting entry to accrued liabilities. For the three months
ended March 31, 2009, we recorded a $641,000 reduction of
general and administrative expense due to the change in fair value of
the warrants. The factors that determine the fair value are not in
our control and may potentially produce a more material impact on
future consolidated statements of operations.
Results of Operations
Three Months Ended March 31, 2009 Compared to Three Months Ended March 31, 2008
Operating Revenues. First quarter 2009 oil and natural gas revenues, which include oil and natural
gas hedging activities (see Note 11 of Notes to Consolidated Financial Statements), decreased $16.3
million (42%) as compared to first quarter 2008 revenues due to a 10% decrease in production
volumes and a 36% decrease in average commodity prices on a natural gas equivalent basis. Oil and
natural gas
28
production volumes totaled 3,340 Mmcfe for the first quarter of 2009 compared to 3,731
Mmcfe for the comparable period of 2008. Our average daily production decreased from 41 Mmcfe
during the first quarter of 2008 to 37 Mmcfe for the first quarter of 2009. First quarter 2009
production was generally lower due to natural production declines.
The following table summarizes the Companys operating revenues, production volumes and average
sales prices for the three months ended March 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
March 31, |
|
|
Increase |
|
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
|
199 |
|
|
|
184 |
|
|
|
8 |
% |
Natural gas (MMcf) |
|
|
2,147 |
|
|
|
2,626 |
|
|
|
(18 |
%) |
Mmcfe |
|
|
3,340 |
|
|
|
3,731 |
|
|
|
(10 |
%) |
|
Average Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
45.62 |
|
|
$ |
86.91 |
|
|
|
(48 |
%) |
Natural gas (per Mcf) |
|
$ |
6.07 |
|
|
$ |
8.55 |
|
|
|
(29 |
%) |
Mmcfe |
|
$ |
6.62 |
|
|
$ |
10.31 |
|
|
|
(36 |
%) |
|
Operating Revenues (000s): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
9,071 |
|
|
$ |
16,006 |
|
|
|
(43 |
%) |
Natural gas |
|
$ |
13,038 |
|
|
$ |
22,442 |
|
|
|
(42 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Total Operating Revenues |
|
$ |
22,109 |
|
|
$ |
38,448 |
|
|
|
(42 |
%) |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses. Oil and natural gas operating expenses on an aggregate basis decreased $1.4
million (24%) to $4.6 million during the first quarter of 2009, compared to $6.1 million in the
first quarter of 2008. On a unit basis, lease operating expenses decreased $0.24 per Mcfe to $1.39
per Mcfe for the first quarter of 2009 from $1.63 per Mcfe for the first quarter of 2008. Oil and
natural gas operating expenses decreased primarily due to decreased workovers, lower insurance
costs, reduced production, and cost saving measures implemented in the field.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes decreased $0.9 million (37%) to
$1.6 million for the first quarter of 2009, compared to $2.6 million during the same period in 2008
primarily because of the decrease in production and to a decrease in taxes per Mcfe. On an
equivalent unit of production basis, severance and ad valorem taxes decreased to $0.49 per Mcfe
from $0.69 per Mcfe for the comparable three-month period. This unit decrease is primarily related
to the decrease in oil and natural gas prices.
Depletion and Depreciation. Depletion and depreciation expense decreased $5.9 million (34%) during
the first quarter of 2009 to $11.8 million, from $17.7 million for the same period of 2008. This
was the result of lower depreciation expense per unit , combined with a decrease in oil and natural
gas production. On a unit basis, depletion and depreciation expense decreased by $1.24 per Mcfe,
to $3.52 per Mcfe for the three months ended March 31, 2009, compared to $4.76 per Mcfe for the
same period in 2008. The reduction in expense per unit is due to the decrease in the carrying value
of oil and gas properties which resulted from the significant impairment write-down to the
properties recorded in December 2008.
29
Impairment of Long-Lived Assets. A decline in oil and natural gas prices as of March 31, 2009,
resulted in the Company recognizing a non-cash impairment totaling $59.5 million of its oil and
natural gas properties under the full cost method of accounting.
General
and Administrative Expense. General and administrative
expense was $3.4 million in the first quarter of 2009
compared to $4.1 million in the first quarter of 2008. The $0.7 million decrease was primarily due to the non-cash
mark to market reduction of $0.6 million in expenses in the first quarter of 2009 of the Companys
General Partner Warrants; see Note 9 elsewhere in this report. On an equivalent unit of production
basis, general and administrative expenses decreased $0.08 per Mcfe to $1.01 per Mcfe for the first
quarter of 2009 compared to $1.09 per Mcfe for the comparable 2008 period primarily due to the
expense reduction due to the General Partner Warrants, partially offset by lower production rates
between the periods.
Interest Expense. Interest expense increased $0.4 million (42%), to $1.6 million for the first
quarter of 2009 in comparison to $1.2 million for the first quarter of 2008. The increase is
primarily a result of higher average debt balances. In addition, a portion of our deferred loan
costs related to the Credit Facility were written off and charged to interest expense.
Taxes on Income. Income tax expense for the first quarter of 2009 was zero, compared to $2.8
million in the first quarter of 2008. The elimination of tax benefit from losses originated in the
fourth quarter of 2008 as a result of the Companys deferred tax asset valuation allowance.
Management believes, given our overall current financial position, that there are significant
uncertainties regarding our ability to generate net profits in the near term; thus a tax asset
valuation allowance sufficient to offset all deferred tax assets has been continuously maintained
since December 2008.
Liquidity and Capital Resources
Working Capital. During the first quarter of 2009, Meridians capital expenditures were internally
financed with cash flow from operations and cash on hand. As of March 31, 2009, the Company had a
cash balance of $5.1 million and a working capital deficit of $109.8 million.
Cash Flows. Net cash provided by operating activities was $8.8 million for the three months ended
March 31, 2009, as compared to $22.8 million for the same period in 2008. The decrease of $14.0
million was primarily due to lower natural gas production volumes and lower crude oil and natural
gas prices, partially offset by lower operating expenses.
Net cash used in investing activities was $15.0 million during the three months ended March 31,
2009, versus $33.8 million in the first three months of 2008 due to decreased capital expenditures
partially offset by lower property sales.
Cash flows used in financing activities during the first three months of 2009 were $2.0 million,
compared to cash provided by financing activities of $6.9 million during the first three months of
2008 primarily due to the net drawdown on the Credit Facility of $10 million in the first quarter
of 2008.
Credit Facility. On December 23, 2004, the Company amended its Credit Facility to provide for a
four-year $200 million senior secured credit facility (the Credit Facility) with Fortis Capital
Corp., as administrative agent, sole lead arranger and bookrunner; Comerica Bank as syndication
agent; and Union Bank of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks
PLC, RZB Finance LLC and Standards Bank PLC completed the syndication group. The initial borrowing
base under the Credit Facility was $130 million. The borrowing base under the Credit Facility was
redetermined by the syndication group to be $115 million effective October 31, 2007.
30
On February 21, 2008, the Company amended the Credit Facility. The lending institutions under the
amended Credit Facility include Fortis Capital Corp. as administrative agent, co-lead arranger and
bookrunner; The Bank of Nova Scotia, as co-lead arranger and syndication agent; Comerica Bank, US
Bank NA and Allied Irish Bank plc each in their respective capacities as lenders (collectively, the
Lenders.) The maturity date was extended to February 21, 2012, and the borrowing base was
redetermined to be $110 million. Interest rates were slightly increased by increasing the range of
the add-on to the prime base rate by 250 basis points on the lower end of the range and by 500
basis points on the higher end of the range; the range of the add-on to the alternative base rate
was increased by 250 basis points on the higher end of the range.
On December 19, 2008, the Company entered into the Second Amendment to Credit Agreement to the
Credit Facility (Second Amendment). The Second Amendment redetermined the borrowing base at $95
million, limiting borrowing to the amount outstanding at December 31, 2008. In addition, interest
rates were increased by increasing the range of the add-on to the prime base rate by 500 basis
points on the lower end of the range and by 750 basis points on the higher end of the range; the
range of the add-on to the alternative base rate was increased by the same amounts.
The terms of the Credit Facility contain numerous covenants and restrictions. Currently, the
Company is in default of a covenant which requires that it maintain a current ratio (as defined in
the Credit Facility) of one to one. The current ratio, as defined, was less than the required one
to one at both December 31, 2008 and March 31, 2009. The Company is also in default of the
requirement that the Companys auditors opinion for the current financial statements be without
modification. The Companys 2008 report of independent registered accounting firm included a going
concern explanatory paragraph expressing substantial doubt about the Companys ability to continue
as a going concern.
The Lenders were informed of the defaults under these covenants. Under the terms of the Credit
Facility, the Lenders have various remedies available in the event of a default, including
acceleration of payment of all principal and interest. On April 13, 2009, the Lenders notified us
that as of the effective date of April 30, 2009, the borrowing base was reduced from its current
$95 million to $60 million. The Credit Facility provides that outstanding borrowings in excess of
the borrowing base must be repaid within 90 days after the redetermination, and we do not currently
have sufficient cash available to repay the shortfall. The borrowing base is determined at the
discretion of the Lenders, based primarily on the value of our proved reserves. The value of our
proved reserves has been significantly reduced during the last several months due to the
precipitous decrease in the prices of oil and natural gas. We are currently in discussions with
the Lenders regarding alternative repayment terms, amortization payments from cash flow, obtaining
waivers on the current events of default that have been previously disclosed, providing additional
security and entering into forbearance agreements. We cannot provide any assurance that our
Lenders will agree to any such arrangements. We are also considering other options for repayment,
including the sale of strategic and nonstrategic assets and obtaining capital from other sources.
We may not be able to sell assets on terms that we consider advantageous to us and our
shareholders, and capital on acceptable terms may not be available
from other sources, or at all. Our inability to obtain
concessions from our Lenders or to execute other alternatives would have a material adverse effect
on our results of operations and financial condition. All indebtedness under the Credit Facility at
December 31, 2008 and March 31, 2009, $95.0 million, have been classified in current liabilities on
the accompanying Consolidated Balance Sheets.
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 Lenders can redetermine the borrowing
base to a lower level than the
31
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. In the event the redetermined borrowing base is less than our outstanding borrowings under
the Credit Facility, the Company will be required to repay the deficit within a 90-day period.
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 repurchases of
common stock, restrictions on incurrence of additional debt, and an unqualified audit report on the
Companys consolidated financial statements. As noted above, at December 31, 2008 and March 31,
2009, the Company is in default of two of these covenants.
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 1.25% to 2.50% 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 2.0% to 3.25%, depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base. At December 31, 2008, the
three-month LIBOR interest rate was 1.425%; at March 31, 2009 it was 1.19%, and the prime rate
remained at 3.25%. During the first quarter of 2009, the Lenders informed the Company that all
outstanding tranches of debt would be converted to prime-based from LIBOR-based upon maturity. The
Credit Facility continues to provide for commitment fees of 0.375% calculated on the difference
between the borrowing base and the aggregate outstanding loans and letters of credit under the
agreements. As of May 1, 2009, outstanding borrowing under the Credit Facility totaled $95.0
million.
Rig Note. On May 2, 2008, the Company, through its wholly owned subsidiary TMR Drilling Corporation
(TMRD), entered into a financing agreement with The CIT Group Equipment Financing, Inc. (CIT).
Under the terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625%,
in order to refinance the purchase of a land-based drilling rig to be used in Company operations.
The rig had been purchased using cash on hand and funds available to the Company under the Credit
Facility. Funds from the new agreement were used to reduce borrowing under the Credit Facility. The
loan is collateralized by the drilling rig, as well as general corporate credit. The term of the
loan is five years; monthly payments of $196,248 for interest and principal are to be made until
the loan is completely repaid at termination of the agreement on May 2, 2013.
Effective as of December 31, 2008, the Companys defaults under the Credit Facility also resulted
in an event of default under our rig note. The remedies available to CIT in the event of default
include acceleration of all principal and interest payments. All indebtedness under the rig note,
$8.8 million at December 31, 2008 and $8.4 million at March 31, 2009, has been classified in
current liabilities on the accompanying Consolidated Balance Sheets as of December 31, 2008 and
March 31, 2009.
CIT was notified of the Companys defaults under the covenants of the Credit Facility, and has not
responded with a notice of any remedies it may choose to pursue.
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.
32
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.
These hedging contracts have been designated as cash flow hedges as provided by SFAS No. 133,
Accounting for Derivative Instruments and Certain Hedging Activities, and any changes in fair
value of the cash flow hedge resulting from ineffectiveness of the hedge is reported in the
consolidated statement of operations as revenues; see Note 11 contained elsewhere in this report.
All other changes in fair value are reported in the statement of comprehensive income as unrealized
gains or losses from hedging activities.
Capital Expenditures. Total capital expenditures for this period were approximately $12.2 million.
Drilling in the first quarter included two wells, both spudded near the end of the fourth
quarter of 2008 in the Austin Chalk play, one operated and one non-operated. Drilling and
recompletions for subsequent quarters will depend on the availability of capital.
The Company anticipates the 2009 capital spending budget will be primarily used for recompletions
and similar work on existing properties, and for lease maintenance costs. We anticipate that the
budget will be significantly lower than in past years, reflecting our expectations of reduced cash
flows due to commodity price declines and the loss of availability of funds under the Credit
Facility. These factors will significantly impact funds available for capital spending. We
currently anticipate funding the 2009 plan utilizing cash flow from operations and cash on hand,
augmented by proceeds from sales of assets as possible.
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.
33
Actual results and trends in the future may differ materially depending on a variety of factors
including, but not limited to the following:
Changes in the price of oil and natural gas. The prices we receive for our oil and natural gas
production and the level of such production are subject to wide fluctuations and depend on numerous
factors that we do not control, including seasonality, worldwide economic conditions, the condition
of the United States economy (particularly the manufacturing sector), foreign imports, political
conditions in other oil-producing countries, the actions of the Organization of Petroleum Exporting
Countries and domestic
government regulation, legislation and policies. Material declines in the prices received for oil
and natural gas could make the actual results differ from those reflected in our forward-looking
statements.
Operating Risks. The occurrence of a significant event against which we are not fully insured
could have a material adverse effect on our financial position and results of operations. Our
operations are subject to all of the risks normally incident to the exploration for and the
production of oil and natural gas, including uncontrollable flows of oil, natural gas, brine or
well fluids into the environment (including groundwater and shoreline contamination), blowouts,
cratering, mechanical difficulties, fires, explosions, unusual or unexpected formation pressures,
pollution and environmental hazards, each of which could result in damage to or destruction of oil
and natural gas wells, production facilities or other property, or injury to persons. In addition,
we are subject to other operating and production risks such as title problems, weather conditions,
compliance with government permitting requirements, shortages of or delays in obtaining equipment,
reductions in product prices, limitations in the market for products, litigation and disputes in
the ordinary course of business. Although we maintain insurance coverage considered to be
customary in the industry, we are not fully insured against certain of these risks either because
such insurance is not available or because of high premium costs. We cannot predict if or when any
such risks could affect our operations. The occurrence of a significant event for which we are not
adequately insured could cause our actual results to differ from those reflected in our
forward-looking statements.
Drilling Risks. Our decision to purchase, explore, develop or otherwise exploit a prospect or
property will depend in part on the evaluation of data obtained through geophysical and geological
analysis, production data and engineering studies, which are inherently imprecise. Therefore, we
cannot assure you that all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause the actual results
to differ from those reflected in our forward-looking statements.
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
after-tax 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.
34
The calculation of the ceiling test and the depletion expense 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.
At March 31, 2009, the unamortized cost of our oil and natural gas properties, net of related
deferred income taxes, exceeded the ceiling under the full cost method of accounting for oil and
natural gas properties. Accordingly, based on March 31, 2009 pricing of $3.76 per Mcf of natural
gas and $49.66 per barrel of oil, in the first quarter of 2009, the Company recognized non-cash
impairment of $59.5 million of the Companys oil and natural gas properties under the full cost
method of accounting. A non-cash impairment of $216.8 million ($203.2 million after tax) was
recognized in the fourth quarter of 2008, based on prices prevailing at the time.
Due to the imprecision in estimating oil and natural gas revenues as well as the potential
volatility in oil and natural gas prices and their effect on the carrying value of our proved oil
and natural gas reserves, there can be no assurance that write-downs in the future will not be
required as a result of factors that may negatively affect the present value of proved oil and
natural gas reserves and the carrying value of oil and natural gas properties, including volatile
oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve
quantities and unsuccessful drilling activities.
At March 31, 2009, we had no cushion (i.e., the excess of the ceiling over our capitalized costs).
Thus, any decrease in prices affecting the end of subsequent accounting periods, net of the effect
of our hedging positions, may require us to record additional impairment charges. Any future
impairment would be impacted by changes in the accumulated costs of oil and natural gas properties,
which may in turn be affected by sales or acquisitions of properties and additional capital
expenditures. Future impairment would also be impacted by changes in estimated future net
revenues, which are impacted by additions and revisions to oil and natural gas reserves. A 10%
decrease in prices would have increased our 2009 non-cash impairment expense by approximately $25.9
million or 44%.
Borrowing base for the Credit Facility. The Amended Credit Facility with Fortis Capital Corp. as
administrative agent, is presently scheduled for borrowing base redetermination dates on a
semi-annual basis with the next such redetermination scheduled for October 31, 2009. The borrowing
base is redetermined on numerous factors including current reserve estimates, reserves that have
recently been added, current commodity prices, current production rates and estimated future net
cash flows. These factors have associated risks with each of them. Significant reductions or
increases in the borrowing base will be determined by these factors, which, to a significant
extent, are not under the Companys control.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
The Company is currently exposed to market risk from hedging contracts changes and changes in
interest rates. A discussion of the market risk exposure in financial instruments follows.
Interest Rates
We are subject to interest rate risk on our long-term fixed interest rate debt and variable
interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the
amended Credit Facility. Interest charged on borrowings under the amended Credit Facility floats
with prevailing interest rates. Changes in interest rates will change the cost of borrowing. Our
default under the Credit Facility poses a more significant interest rate risk, as we may not be
able to continue to borrow at the rates
35
currently in place. Further, we have been informed by the
Lenders that $35 million of the outstanding borrowings under the Credit Facility must be repaid
within 90 days of April 30, 2009. There can be no assurance that the Company will obtain
concessions from the Lenders or be able to execute other alternatives to replace this borrowed
capital at the current rates.
Assuming $95 million remains borrowed under the amended Credit Facility or a successor debt
agreement, we estimate our annual interest expense will change by $0.95 million for each 100 basis
point change in the applicable interest rates.
Hedging Contracts
Management of Financial Risk. The Companys operating environment includes two primary financial
risks which could be addressed through derivatives and similar financial instruments: the risk of
movement in oil and natural gas commodity prices, which impacts revenue, and the risk of interest
rate movements, which impacts interest expense from floating rate debt.
The Company currently does not utilize derivative contracts or any other form of hedging against
interest rate risk.
The Company utilizes derivative contracts to address the risk of adverse oil and natural gas
commodity price fluctuations. While the use of derivative contracts limits the downside risk of
adverse price movements, it may also limit future gains from favorable movements. No derivative
contracts have been entered into for trading purposes, and the Company has the intent to hold each
instrument to maturity. The Companys commodity derivative contracts are considered cash flow
hedges under SFAS 133.
Oil and Natural Gas Hedging Contracts. The Company has historically utilized derivative contracts
to hedge the sale of a portion of its future production. The Companys objective is to reduce the
impact of commodity price fluctuations on both income and cash flow, as well as to protect future
revenues from adverse price movements. Management considered some exposure to market pricing to be
desirable, due to the potential for favorable price movements, but preferred to achieve a measure
of stability and predictability over revenues and cash flows by hedging some portion of production.
The Companys commodity derivative positions as of March 31, 2009 hedge approximately 29% of proved
developed natural gas production and 16% of proved developed oil production during the remaining
terms of all derivative agreements in the aggregate.
The Company has historically chosen derivative contracts in the form of costless collars. These
agreements ensured the Company would receive a minimum (floor) price for the commodity, while
concurrently limiting the price to a specified maximum (ceiling). Typically, the contracts specify
monthly hedged volumes subject to the floor and ceiling prices over a period of 6 to 18 months.
The contracts are settled monthly based on the NYMEX futures contract. Counter parties to these
contracts are large financial institutions that are members of the lending group which is party to
our amended Credit Facility. The following table lists all of the Companys commodity derivative
contracts as of March 31, 2009:
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling |
|
|
Asset (Liability) |
|
|
|
|
|
|
|
Notional |
|
|
Floor Price |
|
|
Price |
|
|
March 31, 2009 |
|
|
|
Type |
|
|
Amount |
|
|
($ per unit) |
|
|
($ per unit) |
|
|
(in thousands) |
|
Natural Gas (mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
860,000 |
|
|
$ |
7.50 |
|
|
$ |
10.45 |
|
|
$ |
2,866 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
530,000 |
|
|
$ |
8.00 |
|
|
$ |
10.30 |
|
|
|
2,012 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
360,000 |
|
|
$ |
8.00 |
|
|
$ |
13.35 |
|
|
|
1,367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas |
|
|
6,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
17,000 |
|
|
$ |
70.00 |
|
|
$ |
93.55 |
|
|
|
298 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
28,000 |
|
|
$ |
80.00 |
|
|
$ |
111.00 |
|
|
|
751 |
|
Apr 2009 Dec 2009 |
|
Collar |
|
|
34,000 |
|
|
$ |
85.00 |
|
|
$ |
128.50 |
|
|
|
1,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Crude Oil |
|
|
2,119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
8,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Special terms in derivative contracts. Although the Companys counterparties provide no
collateral, the master derivative agreements with each counterparty effectively allow the Company,
at its option, so long as it is not a defaulting party, after a default or the occurrence of a
termination event, to set-off an unpaid hedging agreement receivable against the interest of the
counterparty in any outstanding balance under the Credit Facility. In practice, no such set-off has
been made, and all settlements have been made in cash. As of December 31, 2008, however, the
Company is in default of two covenants contained in the Credit Facility, the breach of which is
also a default under the master derivative agreements. Although the Companys hedge counterparties
have continued to make contract payments subsequent to its default, they are not obligated to make
payments to the Company under the hedging agreements while the Companys default is continuing. The
Companys set-off rights under the master derivative agreements cannot be exercised due to such
default. The Companys hedging counterparties may exercise their remedies under the hedging
agreements, and potentially under the Credit Facility, on account of the Companys default, which
includes a right to set-off any amount due to the Company under the derivative agreements against
amounts owed to that counterparty as a Lender under the Credit Facility.
If a counterparty were to default in payment of an obligation under the master derivative
agreements, the Company would be exposed to commodity price fluctuations, and the protection
intended by the hedge would be lost. The value of assets from price risk management would be
impacted. In addition, as expected cash flows from hedging contracts are included in computing
future net revenues, the ceiling test could be impacted, which could result in a non-cash
write-down of oil and natural gas properties.
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 and Chief Accounting Officer, of the
effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the first quarter of
2009. Based upon that evaluation,
37
our Chief Executive Officer and Chief Accounting Officer
concluded that the design and operation of our disclosure controls and procedures are effective.
There have been no significant changes in our internal controls or in other factors during the
first quarter of 2009 that could significantly affect these controls.
Changes in Internal Controls
During the three month period ended March 31, 2009, there were no changes in the Companys internal
control over financial reporting that have materially affected or are reasonably likely to
materially affect such internal control over financial reporting.
PART II OTHER INFORMATION
ITEM 1. Legal Proceedings.
Default under Credit Agreement
As described in Notes 1 and 6, the Company is in default under the terms of the Credit Facility,
the master derivative agreements, and the rig note. The lead or administrative Lenders under each
of these agreements have been informed of the circumstances of default under the Credit Facility.
The Lenders under the Credit Facility have informed the Company that the borrowing base will be
revised downward effective April 30, 2009 from the present $95 million to $60 million; the deficit
must be repaid within 90 days. Also among the remedies available to Lenders under each of these
agreements is acceleration of all principal and interest payments. Accordingly, all such debt,
including the rig note, has been classified as current in the Consolidated Balance Sheets as of
December 31, 2008 and March 31, 2009. The Company is currently unable to predict what further
actions the Lenders may pursue; therefore, the Company has not provided for this matter in its
financial statements at March 31, 2009, other than to reclassify all outstanding debt as current.
The counterparties under the master derivative agreements have not notified the Company of action
they may take, if any, due to the default under those agreements, which arises strictly from the
default under the Credit Facility.
Litigation
H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against
Meridian for damages estimated to exceed several million dollars for Meridians alleged gross
negligence, willful misconduct and breach of fiduciary duty under certain agreements concerning
certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish
in Louisiana, as a result of Meridians satisfying a prior adverse judgment in favor of Amoco
Production Company. Mr. James Bond had been added as a defendant by Hawkins claiming Mr. Bond, when
he was General Manager of Hawkins, did not have the right to consent, could not consent or breached
his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr. James T. Bond
was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He served on the
Board of Directors of the Company from March 1997 to August 2004. After Mr. Bonds employment with
Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian Resource &
Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond was also the
father-in-law of Michael J. Mayell, the Chief Operating Officer of the Company at the time. A
hearing was held before Judge Kay Bates on April 14, 2008. Judge Bates granted Hawkins Motion
finding that Meridian was estopped from arguing that it did not breach its contract with Hawkins as
a result of the United States Fifth Circuits decision in the Amoco litigation. Meridian disagrees
with Judge Bates ruling but the Louisiana First Court of Appeal
38
declined to hear Meridians writ
requesting the court overturn Judge Bates ruling. Meridian filed a motion with Judge Bates asking
that the ruling be made a final judgment which would give Meridian the right to appeal
immediately; however, the Judge declined to grant the motion, allowing the case to proceed to trial.
Management continues to vigorously defend this action on the basis that Mr. Hawkins individually
and through his agent, Mr. Bond, agreed to the course of action adopted by Meridian and further
that Meridians actions were not grossly negligent, but were within the business judgment rule.
Since Mr. Bonds death, a pleading has been filed substituting the proper party for Mr. Bond. The
Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of
this matter or to estimate the amount or range of potential loss should the outcome be unfavorable.
Therefore, the Company has not provided any amount for this matter in its financial
statements at March 31, 2009.
Parsons Exploration litigation. On May 3, 2007, Parsons Exploration Company, LLC (Parsons) filed
a claim against Meridian for damages and specific performance requiring Meridian to assign Parsons
an overriding royalty interest in certain wells the Company has drilled in east Texas. The
complaint alleged that the Company breached its contractual and fiduciary obligations to Parsons
under an Exploration and Prospect Origination Agreement between the parties dated April 22, 2003.
The complaint also alleged that the Company engaged in a civil conspiracy to breach its contractual
and fiduciary obligations to Parsons and tortiously interfered with existing and prospective
business relationships/contracts of Parsons. The Company has recognized an estimated settlement for
this matter in the amount of $2.1 million, which was charged to the full cost pool in the first
quarter of 2009.
Title/lease disputes. Title and lease disputes may arise in the normal course of the Companys
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Environmental litigation. Various landowners have sued Meridian (along with numerous other oil
companies) in lawsuits concerning several fields in which the Company has had operations. The
lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and
punitive damages for alleged breaches of mineral leases and alleged failure to restore the
plaintiffs lands from alleged contamination and otherwise from the Companys oil and natural gas
operations. In some of the lawsuits, Shell Oil Company and SWEPI LP (together, Shell) have
demanded contractual indemnity and defense from Meridian based upon the terms of the acquisition
agreements related to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded
contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement
related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some
cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the
fields. On December 9, 2008 Shell sent Meridian a letter reiterating its demand for indemnity.
Shell has not to date produced all of the supporting documentation for its claim. In the Companys
discussions with Shell, Shell has indicated that it is considering filing an arbitration, but has
not yet initiated a formal proceeding. Meridian denies that it owes any indemnity under the
acquisition agreements; however, the amounts claimed are substantial in nature and if adversely
determined, would have a material adverse effect on the Company. The Company is unable to express
an opinion with respect to the likelihood of an unfavorable outcome of these matters or to estimate
the amount or range of potential loss should any outcome be unfavorable. Therefore, the Company has
not provided any amount for these matters in its financial statements at March 31, 2009.
Litigation involving insurable issues. There are no material legal proceedings involving insurable
issues which exceed insurance limits to which Meridian or any of its subsidiaries is a party or to
which any of its property is subject, other than ordinary and routine litigation incidental to the
business of producing and exploring for crude oil and natural gas.
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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, 2008. There have been no changes to these risk factors during
the quarter ended March 31, 2009.
ITEM 6. Exhibits.
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31.1 |
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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. |
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31.2 |
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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. |
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32.1 |
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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. |
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32.2 |
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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. |
40
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)
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Date: May 11, 2009 |
By: |
/s/ LLOYD V. DELANO
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Lloyd V. DeLano |
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Chief Accounting Officer, Senior Vice
President and Secretary |
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41