e8vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
Of the Securities Exchange Act of 1934
Date
of report (Date of earliest event reported): August 7, 2007
Commission file number: 001-7940
GOODRICH PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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76-0466193
(I.R.S. Employer
Identification No.) |
808 Travis, Suite 1320
Houston, Texas 77002
(Address of principal executive offices)
Registrants telephone number, including area code: (713) 780-9494
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy
the filing obligation of the registrant under any of the following provisions:
o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
TABLE OF CONTENTS
ITEM 8.01. OTHER EVENTS.
On
March 20, 2007, Goodrich Petroleum Company, L.L.C. (the Company) and Malloy Energy Company,
L.L.C., a New York limited liability company collectively with the Company, (the Sellers) closed
the sale of substantially all the Sellers assets located in South Louisiana to a private company
(the Buyer) pursuant to the Purchase and Sale Agreement dated January 12, 2007 between the
Sellers and Buyer. The entry into the Purchase and Sale Agreement was previously disclosed in the
Companys Current Report on Form 8-K dated January 19, 2007 (the January 19, 2007 Current
Report).
The
sale resulted in total proceeds of $74 million, net to the
Company, after normal closing adjustments. A detailed description of the assets sold to the Buyer can be found in
the Purchase and Sale Agreement, which was filed as Exhibit 10.1 to the Companys January 19, 2007
Current Report, and this description is qualified in its entirety by reference to such exhibit.
The Company issued a press release on March 21, 2007, to announce the closing of the
previously announced sale of substantially all of the Companys South Louisiana assets.
The Company reported operations with respect to these properties as discontinued operations in
the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007.
This Current Report on Form 8-K was prepared to provide revised financial information that
presents these sold properties and other properties held for sale as discontinued operations for
all periods presented in the Companys Annual Report on Form 10-K for the year ended December 31,
2006, filed on March 14, 2007 (2006 Form 10-K). It should be noted that the Companys net income
(loss) was not impacted by the reclassification of the companys operations with respect to these
properties to discontinued operations.
Please note, the Company has not otherwise updated the financial information or business
discussion for activities or events occurring after the date this information was presented in the
Companys 2006 Form 10-K. You should read the Companys Quarterly Report on Form 10-Q for the
period ended March 31, 2007 and Current Reports on Form 8-K and any amendments thereto, for updated
information.
This filing includes updated information for the following items included in our 2006 Form
10-K:
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ITEM 6. |
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SELECTED FINANCIAL DATA |
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ITEM 7. |
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MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS |
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ITEM 8. |
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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
2
Item 6. Selected Financial Data
The following table sets forth our selected financial data and other operating
information. The selected consolidated financial data in the table are derived from our
consolidated financial statements. The financial statements reflect the sale, on March 20, 2007,
of our South Louisiana properties as discontinued operations for each period presented.
Discontinued operations in the years 2002, 2003 and 2004 also include the sale in October, 2004 of
our West Texas properties. This data should be read in conjunction with the consolidated financial
statements, related notes and other financial information included herein.
Statement of Operations Data:
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Year Ended December 31, |
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2006 |
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2005 |
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2004 |
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2003 |
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2002 |
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(In thousands, except per share amounts) |
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Revenues: |
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Oil and gas revenues |
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$ |
73,933 |
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$ |
34,986 |
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$ |
3,759 |
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$ |
1,609 |
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1,989 |
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Other |
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838 |
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325 |
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151 |
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477 |
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131 |
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74,771 |
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35,311 |
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3,910 |
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2,086 |
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2,120 |
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Operating Expenses |
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Lease operating expense |
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13,182 |
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3,821 |
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347 |
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507 |
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2,690 |
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Production taxes |
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2,851 |
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1,809 |
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164 |
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90 |
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122 |
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Transportation |
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3,791 |
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558 |
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Depreciation, depletion and amortization |
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37,225 |
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12,214 |
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1,486 |
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900 |
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2,663 |
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Exploration |
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5,888 |
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5,697 |
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955 |
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1,591 |
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562 |
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Impairment of oil and gas properties |
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9,886 |
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340 |
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335 |
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342 |
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General and administrative |
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17,223 |
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8,622 |
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5,821 |
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5,314 |
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4,468 |
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(Gain) loss on sale of assets |
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(23 |
) |
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(235 |
) |
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(50 |
) |
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66 |
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(2,941 |
) |
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90,023 |
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32,826 |
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8,723 |
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8,803 |
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7,906 |
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Operating income (loss) |
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(15,252 |
) |
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2,485 |
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(4,813 |
) |
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(6,717 |
) |
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(5,786 |
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Other income (expense): |
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Interest expense |
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(7,845 |
) |
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(2,359 |
) |
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(1,110 |
) |
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(1,051 |
) |
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(985 |
) |
Gain (loss) on derivatives not qualifying for
hedge accounting |
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38,128 |
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(37,680 |
) |
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2,317 |
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Loss on early extinguishment of debt |
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(612 |
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29,671 |
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(40,039 |
) |
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1,207 |
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(1,051 |
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(985 |
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Income (loss) from continuing operations before
income taxes |
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14,419 |
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(37,554 |
) |
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(3,606 |
) |
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(7,768 |
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(6,771 |
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Income tax (expense) benefit |
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(5,120 |
) |
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13,144 |
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8,594 |
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2,712 |
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2,366 |
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Income (loss) from continuing operations |
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9,299 |
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(24,410 |
) |
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4,988 |
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(5,056 |
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(4,405 |
) |
Discontinued operations including gain on sale of
assets, net of income taxes |
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(7,660 |
) |
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6,960 |
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13,539 |
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8,978 |
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3,454 |
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Income (loss) before cumulative effect of change
in accounting principle |
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1,639 |
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(17,450 |
) |
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18,527 |
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3,922 |
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(951 |
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Cumulative effect of change in accounting
principle net of income taxes |
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(205 |
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Net income (loss) |
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1,639 |
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(17,450 |
) |
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18,527 |
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3,717 |
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(951 |
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Preferred stock dividends |
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6,016 |
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755 |
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633 |
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633 |
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640 |
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Preferred stock redemption premium |
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1,545 |
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Net income (loss) applicable to common stock |
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$ |
(5,922 |
) |
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$ |
(18,205 |
) |
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$ |
17,894 |
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$ |
3,084 |
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$ |
(1,591 |
) |
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Income (loss) per common share from
continuing operations: |
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Basic |
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$ |
0.37 |
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$ |
(1.05 |
) |
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$ |
0.26 |
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$ |
(0.28 |
) |
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$ |
(0.25 |
) |
Diluted |
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$ |
0.37 |
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$ |
(1.05 |
) |
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$ |
0.25 |
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$ |
(0.25 |
) |
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$ |
(0.25 |
) |
Income (loss) per common share from
discontinued operations: |
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Basic |
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(0.31 |
) |
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0.30 |
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|
0.69 |
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0.50 |
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|
0.19 |
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Diluted |
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(0.31 |
) |
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0.30 |
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0.66 |
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0.44 |
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0.19 |
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Weighted average number of common shares outstanding: |
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Basic |
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24,948 |
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23,333 |
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19,552 |
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18,064 |
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17,908 |
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Diluted |
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25,412 |
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23,333 |
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20,347 |
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20,482 |
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17,908 |
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3
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Year Ended December 31, |
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2006 |
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2005 |
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2004 |
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2003 |
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2002 |
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(In thousands, except per share amounts) |
Balance Sheet Data: |
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Total assets |
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$ |
479,264 |
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$ |
296,526 |
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$ |
127,977 |
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$ |
89,182 |
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$ |
78,567 |
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Total long-term debt |
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201,500 |
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30,000 |
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27,000 |
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20,000 |
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18,500 |
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Stockholders equity |
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205,133 |
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181,589 |
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65,307 |
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48,059 |
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44,607 |
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Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
Certain statements in this report, including statements of the future plans, objectives,
and expected performance of the Company, are forward-looking statements that are dependent upon
certain events, risks and uncertainties that may be outside the Companys control, and which could
cause actual results to differ materially from those anticipated. Some of these include, but are
not limited to:
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planned capital expenditures, |
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future drilling activity, |
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our financial condition, |
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business strategy, |
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the market prices of oil and gas, |
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economic and competitive conditions, |
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legislative and regulatory changes and |
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financial market conditions. |
There are numerous uncertainties inherent in estimating quantities of proved oil and gas
reserves and in projecting future rates of production and the timing of development expenditures.
The total amount or timing of actual future production may vary significantly from reserve and
production estimates. The drilling of exploratory wells can involve significant risks, including
those related to timing, success rates and cost overruns. Lease and rig availability, complex
geology and other factors can affect these risks. Although from time to time we make use of futures
contracts, swaps, costless collars and fixed-price physical contracts to mitigate risk,
fluctuations in oil and gas prices, or a prolonged continuation of low prices may substantially
adversely affect the Companys financial position, results of operations and cash flows.
Overview
We are an independent oil and gas company engaged in the exploration, exploitation,
development and production of oil and natural gas properties primarily in the Cotton Valley Trend
of East Texas and Northwest Louisiana. We operate as one segment as each of our operating areas
have similar economic characteristics and each meet the criteria for aggregation as defined in the
Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No.
131, Disclosures about Segments of an Enterprise and Related Information.
We seek to increase shareholder value by growing our oil and gas reserves, production
revenues and operating cash flow. In our opinion, on a long term basis, growth in oil and gas
reserves and production, on a cost-effective basis, are the most important indicators of
performance success for an independent oil and gas company.
Management strives to increase our oil and gas reserves, production and cash flow through
exploration and exploitation activities. We develop an annual capital expenditure budget which is
reviewed and approved by our board of directors on a quarterly basis and revised throughout the
year as circumstances warrant. We take into consideration our projected operating cash flow and
externally available sources of financing, such as bank debt, when establishing our capital
expenditure budget.
We place primary emphasis on our internally generated operating cash flow in managing our
business. For this purpose, operating cash flow is defined as cash flow from operating activities
as reflected in our Statement of Cash Flows. Management considers operating cash flow a more
important indicator of our financial success than other traditional performance measures such as
net income.
4
Our revenues and operating cash flow are dependent on the successful development of our
inventory of capital projects, the volume and timing of our production, as well as commodity prices
for oil and gas. Such pricing factors are largely beyond our control, however, we employ commodity
hedging techniques in an attempt to minimize the volatility of short term commodity price
fluctuations on our earnings and operating cash flow.
Cotton Valley Trend: Expanding Acreage Position and Active Development Drilling Program
Our relatively low risk development drilling program in the Cotton Valley Trend is
primarily centered in and around Rusk, Panola, Angelina, Nacogdoches, Cherokee, Harrison, Smith and
Upshur Counties, Texas and DeSoto, Caddo and Bienville Parishes, Louisiana. We continue to build
our acreage position in the Cotton Valley Trend and now hold approximately 180,000 gross acres as
of February 15, 2007. As of year end, we had drilled and/or logged a cumulative total of 156 Cotton
Valley wells with a success rate slightly in excess of 99%. Our net production volumes from our
Cotton Valley Trend wells aggregated approximately 29,964 Mcfe per day in 2006, or approximately
69% of our total oil and gas production in the period.
Acquisition of Remaining Interests in Dirgin-Beckville Area of Cotton Valley Trend
In early December 2006, we acquired a 14.5% working interest in 22 wells and
approximately 3,300 gross (500 net) acres within the Dirgin-Beckville field in the Cotton Valley
Trend from a private company for $6.1 million. With the additional interest we now own an
approximate 99% working interest in 52 wells and 12,600 gross acres in this field.
Farmout on 21,200 acres in Northwest Louisiana
In November 2006, we announced a definitive farmout agreement covering 21,200 gross acres
in 33 sections (16,000 net acres), in the Alabama Bend field of Bienville Parish, Louisiana. The
Company has farmed in the right to explore for natural gas and oil at no upfront cost. The Company
will own a 100% working interest in the initial well drilled in each of the 33 sections and the
Farmor shall have the right to participate up to 50% for future wells drilled. To maintain the
rights of the entire acreage block, we must commence drilling operations on one well every 90 days
from completion date of the previous well.
Acquisition of Acreage in Angelina River Play in Nacogdoches and Angelina Counties, Texas
On February 7, 2007, we announced the acquisition of drilling and development rights in
approximately 16,800 gross acres (8,380 net acres) in the Angelina River play, on trend with our
existing acreage in Nacogdoches and Angelina Counties, Texas. We acquired a 60% working interest in
the acreage and will operate the joint venture. The acquisition was completed in two separate
transactions. In the initial transaction, we acquired a 40% interest for $2.0 million from a
private company. We also agreed to carry the private company for a 20% interest in the drilling of
five wells. In the second transaction, we purchased the remaining 20% interest in the acreage in a
like-kind exchange for our 30% interest in the Mary Blevins field in Smith County, Texas.
South Louisiana Operations: 2007 Sale of Assets
On January 12, 2007, the Company and Malloy Energy Company, LLC (Malloy Energy) entered
into a Purchase and Sale Agreement with a private company for the sale of substantially all of the
Companys oil and gas properties in South Louisiana. The total sales price for the Companys
interest in the oil and gas properties was approximately $100 million, effective July 1, 2006. The
total sales price for Malloy Energys interests in these properties was approximately $30 million
with the same effective date. See Note 11 Related Party Transactions to our consolidated
financial statements for additional information regarding Malloy Energy. Both the Company and
Malloy Energys total consideration was reduced by an amount equal to its proportionate share of
the greater of $20 million or normal closing adjustments. The adjusted sales price for the
Companys interest was $77 million. The effective date of the transaction was July 1, 2006 and the
closing date of the sale was late March, 2007. Had we completed this transaction at the end
of 2006, our proved reserves would have been reduced by approximately 31,700 MMcfe. Average
daily production for these properties for the fiscal year-ending December 31, 2006, was
approximately 12,904 Mcfe or about 30% of the Companys total production for 2006. This sale will
allow us to focus the majority of our efforts on the development of our Cotton Valley Trend
acreage, as well as reduce operating costs per unit of production going forward.
Overview of 2006 Results
2006 Financial and operating highlights include:
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We increased our oil and gas production volumes on
continuing operations 178 percent over 2005. Production averaged 30.5
MMcfe/d compared to 11.0 MMcfe/d in 2005. |
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Our 2006 oil and gas revenues for continuing operations
totaled $73.9 million compared to $35.0 million in 2005, a 111
percent increase. |
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Net cash provided by operating activities increased $19.6 million from 2005, to $65.1 million. |
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Estimated proved reserves grew 19 percent to approximately
206.2 Bcfe (approximately 187.0 Bcf of natural gas and 3.2 |
5
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MMBbls of oil and condensate), with a pre-tax present value of
future net cash flows, discounted at 10%, of $214.2 million and
an after-tax present value of discounted future net cash flows
of $200.3 million. |
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Capital expenditures totaled $269.4 million in 2006, versus $164.6 million in 2005. |
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As operator, we successfully drilled, completed and placed in production 101 wells during calendar year 2006. |
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We issued $175.0 million in 3.25% convertible senior notes
due 2026, completely paying off our Second Lien Term Loan and
substantially reducing our bank revolver debt. |
Summary Operating Information:
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Year Ended December 31, |
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Year Ended December 31, |
|
|
2006 |
|
2005 |
|
Variance |
|
2005 |
|
2004 |
|
Variance |
|
|
(in thousands, except for price data) |
Net Production- Continuing Operations: |
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Natural gas (MMcf) |
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10,500 |
|
|
|
3,786 |
|
|
|
6,714 |
|
|
|
177 |
% |
|
|
3,786 |
|
|
|
408 |
|
|
|
3,378 |
|
|
|
828 |
% |
Oil and gas condensate (MBbls) |
|
|
106 |
|
|
|
38 |
|
|
|
68 |
|
|
|
179 |
% |
|
|
38 |
|
|
|
33 |
|
|
|
5 |
|
|
|
15 |
% |
Total (Mmcfe) |
|
|
11,135 |
|
|
|
4,012 |
|
|
|
7,123 |
|
|
|
178 |
% |
|
|
4,012 |
|
|
|
608 |
|
|
|
3,404 |
|
|
|
560 |
% |
Average daily production (Mmcfe/d) |
|
|
30,507 |
|
|
|
10,990 |
|
|
|
19,517 |
|
|
|
178 |
% |
|
|
10,990 |
|
|
|
1,661 |
|
|
|
9,329 |
|
|
|
562 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production- Discontinued Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf) |
|
|
2,501 |
|
|
|
2,451 |
|
|
|
50 |
|
|
|
2 |
% |
|
|
2,451 |
|
|
|
4,410 |
|
|
|
(1,959 |
) |
|
|
(44 |
%) |
Oil and gas condensate (MBbls) |
|
|
368 |
|
|
|
370 |
|
|
|
(2 |
) |
|
|
(1 |
%) |
|
|
370 |
|
|
|
442 |
|
|
|
(72 |
) |
|
|
(16 |
%) |
Total (Mmcfe) |
|
|
4,710 |
|
|
|
4,674 |
|
|
|
36 |
|
|
|
1 |
% |
|
|
4,674 |
|
|
|
7,060 |
|
|
|
(2,386 |
) |
|
|
(34 |
%) |
Average daily production (Mmcfe/d) |
|
|
12,904 |
|
|
|
12,805 |
|
|
|
99 |
|
|
|
1 |
% |
|
|
12,805 |
|
|
|
19,289 |
|
|
|
(6,484 |
) |
|
|
(34 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues- Continuing Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
$ |
67,372 |
|
|
$ |
33,015 |
|
|
$ |
34,357 |
|
|
|
104 |
% |
|
$ |
33,015 |
|
|
$ |
2,573 |
|
|
$ |
30,442 |
|
|
|
1183 |
% |
Oil and condensate |
|
|
6,561 |
|
|
|
1,971 |
|
|
|
4,590 |
|
|
|
233 |
% |
|
|
1,971 |
|
|
|
1,186 |
|
|
|
785 |
|
|
|
66 |
% |
Natural gas, oil and condensate |
|
|
73,933 |
|
|
|
34,986 |
|
|
|
38,947 |
|
|
|
111 |
% |
|
|
34,986 |
|
|
|
3,759 |
|
|
|
31,227 |
|
|
|
831 |
% |
Operating revenues |
|
|
74,771 |
|
|
|
35,311 |
|
|
|
39,460 |
|
|
|
112 |
% |
|
|
35,311 |
|
|
|
3,910 |
|
|
|
31,401 |
|
|
|
803 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
90,023 |
|
|
|
32,826 |
|
|
|
57,197 |
|
|
|
174 |
% |
|
|
32,826 |
|
|
|
8,723 |
|
|
|
24,103 |
|
|
|
276 |
% |
Operating income (loss) |
|
|
(15,252 |
) |
|
|
2,485 |
|
|
|
(17,737 |
) |
|
|
(714 |
%) |
|
|
2,485 |
|
|
|
(4,813 |
) |
|
|
7,298 |
|
|
|
(152 |
%) |
Net Income (loss) applicable
to common stock |
|
$ |
(5,922 |
) |
|
$ |
(18,205 |
) |
|
$ |
12,283 |
|
|
|
(67 |
%) |
|
$ |
(18,205 |
) |
|
$ |
17,894 |
|
|
$ |
(36,099 |
) |
|
|
(202 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized Sales price Per Unit
From Continuing Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price (per Mcf) |
|
|
6.42 |
|
|
|
8.72 |
|
|
|
(2.30 |
) |
|
|
(26 |
%) |
|
|
8.72 |
|
|
|
6.31 |
|
|
|
2.41 |
|
|
|
38 |
% |
Average realized price (per Bbl) |
|
|
62.03 |
|
|
|
52.47 |
|
|
|
9.56 |
|
|
|
18 |
% |
|
|
52.47 |
|
|
|
35.58 |
|
|
|
16.89 |
|
|
|
47 |
% |
Average realized price (per Mcfe) |
|
$ |
6.64 |
|
|
$ |
8.72 |
|
|
$ |
(2.08 |
) |
|
|
(24 |
%) |
|
$ |
8.72 |
|
|
$ |
6.18 |
|
|
$ |
2.54 |
|
|
|
41 |
% |
Results of Operations
The financial statements include discontinued operations presentation for our assets located
in South Louisiana. See Note 12 Acquisitions and Divestures to our consolidated financial
statements.
Operating Income
Year ended December 31, 2006 compared to year ended December 31, 2005
Operating revenues from continuing operations increased 112% or $39.5 million to a total
of $74.8 million in 2006 compared to 2005. The increase resulted from an 178% increase in
production volumes. The drilling, completion and placing into production of 101 operated wells in
the Cotton Valley Trend led to natural gas production more than doubling in 2006. The average
realized price for natural gas fell in 2006 by 26% to $6.42 per Mcf. The average realized oil price
was strong in 2006, increasing 18% to $62.03 per Bbl.
Year ended December 31, 2005 compared to year ended December 31, 2004
Operating revenues from continuing operations increased 803% or $31.4 million in 2005
compared to 2004. This increase resulted from an increase in oil and gas production volumes, due to
a substantial increase in Cotton Valley Trend production, as well as higher average oil and gas
prices. We placed 45 Cotton Valley Trend wells on production in 2005. Initial production from the
Cotton Valley Trend commenced in June 2004 and we ended 2004 with 11 wells on production.
6
Operating Expenses per Mcfe
From Continuing Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
Variance |
|
2005 |
|
2004 |
|
Variance |
Lease operating expense |
|
$ |
1.18 |
|
|
$ |
0.95 |
|
|
$ |
0.23 |
|
|
|
24 |
% |
|
$ |
0.95 |
|
|
$ |
0.57 |
|
|
$ |
0.38 |
|
|
|
67 |
% |
Production taxes |
|
|
0.26 |
|
|
|
0.45 |
|
|
|
(0.19 |
) |
|
|
(42 |
%) |
|
|
0.45 |
|
|
|
0.27 |
|
|
|
0.18 |
|
|
|
67 |
% |
Transportation |
|
|
0.34 |
|
|
|
0.14 |
|
|
|
0.20 |
|
|
|
143 |
% |
|
|
0.14 |
|
|
|
|
|
|
|
0.14 |
|
|
|
|
|
Depreciation, depletion and
amortization |
|
|
3.34 |
|
|
|
3.04 |
|
|
|
0.30 |
|
|
|
10 |
% |
|
|
3.04 |
|
|
|
2.44 |
|
|
|
0.60 |
|
|
|
25 |
% |
Exploration |
|
|
0.53 |
|
|
|
1.42 |
|
|
|
(0.89 |
) |
|
|
(63 |
%) |
|
|
1.42 |
|
|
|
1.57 |
|
|
|
(0.15 |
) |
|
|
(10 |
%) |
Impairment of oil and gas properties |
|
|
0.89 |
|
|
|
0.08 |
|
|
|
0.81 |
|
|
|
1013 |
% |
|
|
0.08 |
|
|
|
|
|
|
|
0.08 |
|
|
|
|
|
General and administrative |
|
|
1.55 |
|
|
|
2.15 |
|
|
|
(0.60 |
) |
|
|
(28 |
%) |
|
|
2.15 |
|
|
|
9.57 |
|
|
|
(7.42 |
) |
|
|
(78 |
%) |
Operating Expenses
Year ended December 31, 2006 compared to year ended December 31, 2005
Lease operating expense (LOE) was $13.2 million for 2006 compared to $3.8 million for
2005. Given the rapid pace of our development program in the Cotton Valley Trend in 2006, we
experienced significant increases in two major components of LOE, salt water disposal costs ($4.1
million) and compressor rental expense ($2.9 million). With the planned installation of our low
pressure gathering system in this region, we expect to see a decline in the per unit LOE charges in
2007. Higher workover activity also contributed to a higher cost per Mcfe in 2006. The majority of
this activity occurred during the fourth quarter.
Production taxes were $2.9 million for 2006 versus $1.8 million in 2005. The reduction in
production taxes per Mcfe resulted from rebates approved by the State of Texas of $1.3 million.
These severance tax rebates relate to a number of our wells which have been approved as high cost
tight gas sand wells, allowing us to pay a lower severance tax rate for up to 10 years following
certification by the State.
Transportation expense was $3.8 million for 2006 compared to $0.6 million for 2005. The
significant increase in transportation expense was due to the requirement for longer transportation
segments in our Cotton Valley Trend properties. As our volumes from the Cotton Valley Trend
expanded over 181% during 2006, our transportation expense increased accordingly.
Depletion, depreciation and amortization expense (DD&A) was $37.2 million for the year
ended December 31, 2006, versus $12.2 million for the year ended December 31, 2005, with the
increase due to higher production volumes and higher DD&A rates. The higher rates are a result of
an increase in capitalized development costs.
Exploration expense for the year ended December 31, 2006, was $5.9 million versus $5.7
million for the year ended December 31, 2005. Leasehold amortization was $4.8 million versus $2.8
million in 2005.
We recorded an impairment expense of $9.9 million in the year ended December 31, 2006,
all of it being determined in conjunction with the receipt of the independent engineers final
report on reserves as of that date. Of the total expense, $8.4 million related to two fields in
East Texas which were not a part of the Companys primary Cotton Valley Trend acreage position, and
the remaining $1.5 million was spread among several minor properties.
General and administrative (G&A) expenses increased to $17.2 million for the year ended
December 31, 2006, from $8.6 million for the year ended December 31, 2005. Stock-based
compensation, which consists of the amortization of restricted stock awards and expense associated
with our stock option plan, increased to $6.0 million for the year ended December 31, 2006,
compared to $1.4 million in 2005. We adopted SFAS 123R on January 1, 2006. SFAS 123R requires new,
modified and unvested share-based payment transactions with employees to be measured at fair value
and recognized as compensation expense over the requisite service period. See Note 2 Stock-Based
Compensation to our consolidated financial statements for additional information.
Year ended December 31, 2005 compared to year ended December 31, 2004
Lease operating expense was $3.8 million for the year ended December 31, 2005 versus $0.3
million for the year ended December 31, 2004, with the increase primarily due to an increase in
Cotton Valley Trend production volumes.
Production taxes were $1.8 million for the year ended December 31, 2005 compared to $0.2
million for the year ended December 31, 2004, due to an increase in Cotton Valley Trend production
volumes and product prices.
DD&A was $12.2 million for the year ended December 31, 2005, versus $1.5 million for the
year ended December 31, 2004, with the increase due to higher production volumes and higher DD&A
rates. The higher rates are a result of an increase in capitalized development costs.
7
Exploration expense for the year ended December 31, 2005 was $5.7 million versus $1.0
million for the year ended December 31, 2004, primarily due to increased dry hole costs from an
exploratory well drilled in East Baton Rouge Parish, Louisiana, and higher non-producing leasehold
amortization expense associated with the expansion of our Cotton Valley Trend acreage position.
We recorded an impairment expense of $0.3 million in the recorded value of one property
for the year ended December 31, 2005, due to sooner than anticipated depletion of reserves.
G&A increased to $8.6 million for the year ended December 31, 2005, from $5.8 million for
the year ended December 31, 2004. This increase was primarily due to higher compensation related
costs due to an approximate 25% increase in the number of employees in 2005 and professional fees
related to the implementation of the requirements of Section 404 of the Sarbanes-Oxley Act of 2002.
Stock-based compensation, which consists of the amortization of restricted stock awards, increased
to $1.1 million for the year ended December 31, 2005, compared to $0.6 million for the comparable
period in 2004 due to the vesting of awards previously granted.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
|
(in thousands) |
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
$ |
(7,845 |
) |
|
$ |
(2,359 |
) |
|
$ |
(1,110 |
) |
Gain (loss) on derivatives not qualifying for hedge accounting |
|
|
38,128 |
|
|
|
(37,680 |
) |
|
|
2,317 |
|
Loss on early extinguishment of debt |
|
|
(612 |
) |
|
|
|
|
|
|
|
|
Income tax (expense) benefit |
|
|
(5,120 |
) |
|
|
13,144 |
|
|
|
8,594 |
|
Income (loss) from discontinued operations, net of tax |
|
|
(7,660 |
) |
|
|
6,960 |
|
|
|
13,539 |
|
Average total borrowings |
|
$ |
99,542 |
|
|
$ |
30,417 |
|
|
$ |
22,958 |
|
Weighted average interest rate |
|
|
7.5 |
% |
|
|
7.0 |
% |
|
|
3.8 |
% |
Other Income (Expense)
Year ended December 31, 2006 compared to December 31, 2005
Interest expense was $7.8 million for 2006, compared to $2.4 million for 2005, with the
increase primarily attributable to a higher level of average borrowings in 2006.
Gain on derivatives not qualifying for hedge accounting relates to our ineffective gas
hedges for the entire year and for our ineffective oil hedges for the fourth quarter, and amounted
to $38.1 million for the year ended December 31, 2006, compared to a loss
of $37.7 million for the year ended December 31, 2005. The gain in 2006 includes an unrealized
gain of $40.2 million in the mark to market value of our ineffective gas and oil hedges and a
realized loss of $2.1 million for the effect of settled derivatives on our ineffective gas and oil
hedges. Our natural gas hedges were ineffective again in 2006, and certain oil hedges were deemed
ineffective in the fourth quarter of 2006 thereby rendering all of our commodity derivatives
ineffective. For these ineffective hedges, we are required to reflect the changes in the fair value
of the hedges in earnings rather than in accumulated other comprehensive loss, a component of
stockholders equity. As applied to our hedging program, there must be a high degree of correlation
between the actual prices received and the hedge prices in order to justify treatment as cash flow
hedges pursuant to SFAS 133. We perform historical correlation analyses of the actual and hedged
prices over an extended period of time. In the fourth quarter of 2006, we determined that certain
of our oil hedges which had previously been effective, fell short of the effectiveness guidelines
to be accounted for as cash flow hedges. To the extent that our hedges are deemed to be ineffective
in the future, we will be exposed to volatility in earnings resulting from changes in the fair
value of our hedges.
We fully paid off our Second Lien Term loan in early December 2006 with the proceeds of
the 3.25% convertible senior notes offering. In the fourth quarter of 2006, we wrote off remaining
deferred loan financing costs of $0.6 million which resulted from the initial funding of this loan
and a subsequent amendment.
Income tax expense on continuing operations
of $5.1 million which was non-cash represents
35.5% of the pre-tax income in 2006. Income tax benefit of $13.1 million in 2005 represents 35% of
pre-tax loss in 2005. The net deferred tax asset as of December 31, 2006, is expected to be
realized based upon expected utilization of tax net operating loss carryforwards and the projected
reversal of temporary differences.
Loss, net of tax on discontinued operations was $7.7 million for the year ended December 31,
2006 compared to income, net of tax on discontinued operations of $7.0 million for the year ended
December 31, 2005, representing substantially all of our oil and gas properties sold or held for
sale in South Louisiana. See Note 12 Acquisitions and Divestitures to our consolidated financial
statements for a further discussion of our discontinued operations.
8
Year ended December 31, 2005 compared to year ended December 31 2004
Interest expense was $2.4 million for the year ended December 31, 2005, compared to $1.1
million for the year ended December 31, 2004, with the increase primarily attributable to a higher
level of average borrowings in 2005 and a higher total interest rate.
Loss on derivatives not qualifying for hedge accounting relates to our ineffective gas
hedges and amounted to $37.7 million for the year ended December 31, 2005, compared to a gain of
$2.3 million for the year ended December 31, 2004. The loss in 2005 is related to the change in
fair value of our ineffective gas hedges. Since our natural gas hedges were deemed ineffective,
beginning in the fourth quarter of 2004, we have been required to reflect the changes in the fair
value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a
component of stockholders equity. In the fourth quarter of 2004, we initially determined that our
gas hedges fell short of the effectiveness guidelines to be accounted for as cash flow hedges and,
likewise, made the same determination in each of the four quarters of 2005.
Income taxes from continuing operations were benefits of $13.1 million
and $8.6 million
for the years ended December 31, 2005 and 2004, respectively, representing 35% of the pre-tax
losses and the $7.3 million revision of the deferred tax valuation allowance in 2004.
Income net of tax from discontinued operations was $7.0 million for the year ended
December 31, 2005 compared to income net of tax from discontinued operations of $13.5 million for
the year ended December 31, 2004. Income net of tax from discontinued operations for 2004 consisted
of $12.8 million from operations of our oil and gas properties in South Louisiana and $0.7 million
from the after-tax gain realized on the sale of our operated interests in the Marholl and Sean Andrew
fields, along with our non-operated interests in the Ackerly field, all of which were located in
West Texas.
Liquidity and Capital Resources
Our principal requirements for capital are to fund our exploration and development
activities and to satisfy our contractual obligations. These obligations include the repayment of
debt and any amounts owing during the period relating to our hedging positions. Our uses of capital
include the following:
|
|
|
Drilling and completing new natural gas and oil wells; |
|
|
|
|
Constructing and installing new production infrastructure; |
|
|
|
|
Acquiring and maintaining our lease position, specifically in the Cotton Valley Trend; |
|
|
|
|
Plugging and abandoning depleted or uneconomic wells. |
Our capital budget for 2007 is $275 million. We continue to evaluate our capital budget
throughout the year.
Future commitments
The table below provides estimates of the timing of future payments that we are obligated
to make based on agreements in place at December 31, 2006. See Note 4, Long-Term Debt and Note
10, Commitments and Contingencies to our consolidated financial statements for additional
information.
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
After |
|
|
|
Note |
|
Total |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2011 |
|
|
|
(in thousands) |
|
Contractual Obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long term debt (1) |
|
4 |
|
$ |
201,500 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
26,500 |
|
|
$ |
175,000 |
|
|
$ |
|
|
Operating lease for office
space |
|
10 |
|
|
1,992 |
|
|
|
701 |
|
|
|
710 |
|
|
|
491 |
|
|
|
48 |
|
|
|
42 |
|
|
|
|
|
Drilling rig commitments |
|
10 |
|
|
80,247 |
|
|
|
45,983 |
|
|
|
24,956 |
|
|
|
9,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation contracts |
|
10 |
|
|
2,159 |
|
|
|
758 |
|
|
|
540 |
|
|
|
540 |
|
|
|
321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations (2) |
|
|
|
$ |
285,898 |
|
|
$ |
47,442 |
|
|
$ |
26,206 |
|
|
$ |
10,339 |
|
|
$ |
26,869 |
|
|
$ |
175,042 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The $175.0 million convertible senior notes have a provision at the
end of years 5, 10 and 15, for the investors to demand payment on
these dates; the first such date is December 1, 2011. |
|
(2) |
|
This table does not include the estimated liability for
dismantlement, abandonment and restoration costs of oil and gas
properties of $9.6 million. The Company records a separate liability
for the fair value of this asset retirement obligation. See Note 3,
Asset Retirement Obligation to our consolidated financial
statements. |
9
Capital Resources
We intend to fund our capital expenditure program, contractual commitments, including
settlement of derivative contracts and future acquisitions with cash flows from our operations,
borrowings under our revolving bank credit facility and the proceeds from the 2007 sale of South
Louisiana properties. In the future, we may also access public markets to issue additional debt
and/or equity securities.
At December 31, 2006, we had $123.5 million of excess borrowing capacity under our
revolving bank credit facility. Our primary sources of cash during 2006 were from funds generated
from operations, bank borrowings and proceeds received from the issuance of $175.0 million of
convertible notes in December 2006. Cash was used primarily to fund exploration and development
expenditures. During 2006 we made aggregate cash payments of $7.3 million for interest. There were
no payments made in 2006 for federal income taxes. The table below summarizes the sources of cash
during 2006, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
Year Ended December 31, |
|
Cash flow statement information: |
|
2006 |
|
|
2005 |
|
|
Variance |
|
|
2005 |
|
|
2004 |
|
|
Variance |
|
|
|
(in thousands) |
|
Net cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provided by operating activities |
|
$ |
65,133 |
|
|
$ |
45,562 |
|
|
$ |
19,571 |
|
|
$ |
45,562 |
|
|
$ |
41,028 |
|
|
$ |
4,534 |
|
Used in investing activities |
|
|
(258,737 |
) |
|
|
(163,571 |
) |
|
|
(95,166 |
) |
|
|
(163,571 |
) |
|
|
(45,414 |
) |
|
|
(118,157 |
) |
Provided by financing activities |
|
|
179,946 |
|
|
|
134,402 |
|
|
|
45,544 |
|
|
|
134,402 |
|
|
|
6,346 |
|
|
|
128,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase(decrease) in cash
and cash equivalents |
|
$ |
(13,658 |
) |
|
$ |
16,393 |
|
|
$ |
(30,051 |
) |
|
$ |
16,393 |
|
|
$ |
1,960 |
|
|
$ |
14,433 |
|
At December 31, 2006, we had a working capital deficit of $22.2 million and
long-term debt of $201.5 million. The working capital deficit was due to the typical timing
difference between the expenditure of funds and accruals resulting from drilling and completion
activities.
Cash Flows
Year ended December 31, 2006 compared to year ended December 31, 2005
Operating activities. Cash flow from operations is dependent upon our ability to
increase production through development, exploration and acquisition activities and the price of
oil and natural gas. Our cash flow from operations is also impacted by changes in working capital.
Net cash provided by operating activities increased to $65.1 million, up 43% from $45.6 million in
2005. As previously mentioned, the 112% increase in operating revenues due to higher production
volumes from our continuing operations drove the increased cash flow in 2006. Operating cash flow
amounts are net of changes in our current assets and current liabilities, which resulted in
increases of $4.9 million and $13.2 million for the years ended December 31, 2006 and 2005,
respectively.
Investing activities. Net cash used in investing activities was $258.7 million for the
year ended December 31, 2006, compared to $163.6 million for 2005. Of the $258.7 million,
approximately $211.0 million was spent for drilling and completion activities in the Cotton Valley
Trend, versus $139.9 million in 2005.
Financing activities. Net cash provided by financing activities was $179.9 million in
2006 versus $134.4 million in 2005. The majority of our net financing cash flows came from the
$175.0 million in convertible note proceeds, and the $29.0 million in convertible preferred
proceeds received in 2006.
Year ended December 31, 2005 compared to year ended December 31, 2004
Operating activities. Net cash provided by operating activities increased to $45.6
million, up 11% from $41.0 million in 2004. The increases in 2005 were a result of the increases in
natural gas and crude oil prices and production levels in 2005 compared to 2004, partially offset
by increases in lease operating expenses, exploration expenses and general and administrative
expenses. Including the effect of settled derivatives, sales of oil and gas increased $31.2 million
in 2005 compared to 2004, with realized crude oil and natural gas prices and production volumes
both increasing in 2005 compared to 2004. Operating cash flow amounts are net of changes in our
current assets and current liabilities, which resulted in increases to our operating cash flow in
the amounts of $13.2 million and $14.1 million, respectively, in the years ended December 31, 2005
and 2004, reflecting increased revenue and expenditure activity associated with our Cotton Valley
Trend wells.
Investing activities. Net cash used in investing activities was $163.6 million for the
year ended December 31, 2005, compared to $45.4 million for the year ended December 31, 2004. For
the year ended December 31, 2005, capital expenditures totaled $164.6
10
million primarily due to
development on our Cotton Valley Trend wells, which accounted for 85% of the capital costs incurred
in 2005. For the year ended December 31, 2004, capital expenditures totaled $47.5 million, as we
incurred substantial drilling and leasehold acquisition costs in East Texas and Northwest Louisiana
and participated in the drilling of two successful exploratory wells and one successful sidetrack
well in the Burrwood/West Delta 83 field. Offsetting these capital expenditures were sales of
non-core properties in West Texas and another minor property in the total amount of $2.1 million.
Financing activities. Net cash provided by financing activities was $134.4 million for
the year ended December 31, 2005, compared to $6.4 million for the year ended December 31, 2004. In
May 2005, we completed a public offering of 3,710,000 shares of our common stock resulting in net
proceeds of $53.1 million which was used to repay all then outstanding indebtedness to BNP under a
senior credit facility. On December 21, 2005, we issued and sold 1,650,000 shares of our Series B
Convertible Preferred Stock for net proceeds as well as bank borrowings of approximately $79.8
million through a private placement.
Our senior credit facility and term loan include certain financial covenants with which
we were in compliance as of December 31, 2006. We do not anticipate a lack of borrowing capacity
under our senior credit facility or term loan in the foreseeable future due to an inability to meet
any such financial covenants nor a reduction in our borrowing base.
3.25% Convertible Senior Notes
In early December 2006, we issued $125.0 million in convertible senior notes. The intial
purchasers option was exercised in full and increased the principal amount to $175.0 million. The
notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes will
be our senior unsecured obligations and will rank equally in right of payment to all of our other
existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually and paid
semi-annually on June 1 and December 1 beginning June 1, 2007. Prior to December 1, 2011, the notes
will not be redeemable. On or after December 11, 2011, we may redeem for cash all or a portion of
the notes, and the investors may require us to repay the notes on each of December 11, 2011, 2016
and 2021. The notes are convertible into shares of our common stock at a rate equal to the sum of:
a) 15.1653 shares per $1,000 principal amount of notes (equal to a base conversion
price of approximately $65.94 per share) plus,
b) an additional amount of shares per $1,000 of principal amount of notes equal to
the incremental share factor (2.6762), multiplied by a fraction, the numerator of which is the
applicable stock price less the base conversion price and the denominator of which is the
applicable stock price.
Share Lending Agreement
With the offering of the 3.25% convertible senior notes we agreed to lend an affiliate of
Bear, Stearns & Co. (BSC) a total of 3,122,263 shares of our common stock. The shares of stock were
lent to the affiliate of BSC under the Share Lending Agreement. Under this agreement, BSC is
entitled to offer and sell such shares and use the sale to facilitate the establishment of a hedge
position by investors in the notes. BSC will receive all proceeds from such common stock offerings
and lending transactions under this agreement. We will not receive any of the proceeds from these
transactions. BSC is obligated to return the shares to us in the event of certain circumstances,
including the redemption of the notes or the conversion of shares pursuant to the terms of the
3.25% convertible notes offering.
The 3,122,263 shares of common stock outstanding as of December 31, 2006, under the Share
Lending Agreement are required to be returned to the Company. The shares are treated in basic and
diluted earnings per share as if they were already returned and retired. There is no impact of the
shares of common stock lent under the Share Lending Agreement in the earnings per share
calculation.
Senior Credit Facility
In 2005, we amended our existing credit agreement and entered into an amended and
restated senior credit agreement (the Senior Credit Facility) and a second lien term loan (the
Term Loan) that expanded our borrowing capabilities and extended our credit facility for an
additional two years. Total lender commitments under the Senior Credit Facility were $200.0 million
which matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are
subject to periodic redeterminations of the borrowing base, which is currently established at
$150.0 million, and is scheduled to be redetermined in late March 2007, based upon our 2006
year-end reserve report. With a portion of the net proceeds of the offering of 3.25% Convertible
Senior Notes in December 2006, we fully repaid and extinguished the $50.0 million Term Loan and
repaid $113.5 million of the Revolving borrowings under the Senior Credit Facility. Interest on
revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option,
at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on
borrowing base utilization.
The terms of the Senior Credit Facility require us to maintain certain covenants.
Capitalized terms are defined in the credit agreement. The covenants include:
11
|
|
|
Current Ratio of 1.0/1.0; |
|
|
|
|
Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and |
|
|
|
|
Total Debt no greater than 3.5 times EBITDAX (1) for the trailing four quarters. |
|
|
|
(1) |
|
EBITDAX is defined as Earnings before interest expense, income tax, DD&A and exploration expense. |
As of December 31, 2006, we were in compliance with all of the financial covenants of the
credit agreement.
Series B Convertible Preferred Stock
Our Series B Convertible Preferred Stock (the Series B Convertible Preferred Stock) was
initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds
of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Convertible
Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and
bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March
15, 2006. If we fail to pay dividends on our Series B Convertible Preferred Stock on any six
dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased
by 1.0% until we have paid all dividends on our Series B Convertible Preferred Stock for all
dividend periods up to and including the dividend payment date on which the accumulated and unpaid
dividends are paid in full.
Each share is convertible at the option of the holder into our common stock, par value
$0.20 per share (the Common Stock) at any time at an initial conversion rate of 1.5946 shares of
Common Stock per share, which is equivalent to an initial conversion price of approximately $31.36
per share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock, we may
choose to deliver the conversion value to holders in cash, shares of Common Stock, or a combination
of cash and shares of Common Stock.
If a fundamental change occurs, holders may require us in specified circumstances to
repurchase all or part of the Series B Convertible Preferred Stock. In addition, upon the
occurrence of a fundamental change or specified corporate events, we will under
certain circumstances increase the conversion rate by a number of additional shares of Common
Stock. A fundamental change will be deemed to have occurred if any of the following occurs:
|
|
|
We consolidate or merge with or into any person or convey,
transfer, sell or otherwise dispose of or lease all or
substantially all of our assets to any person, or any person
consolidates with or merges into us or with us, in any such
event pursuant to a transaction in which our outstanding voting
shares are changed into or exchanged for cash, securities, or
other property, or |
|
|
|
|
We are liquidated or dissolved or adopt a plan of liquidation or dissolution. |
A fundamental change will not be deemed to have occurred if at least 90% of the
consideration in the case of a merger or consolidation under the first clause above consists of
common stock traded on a U.S. national securities exchange and the Series B Preferred Stock becomes
convertible solely into such common stock.
On or after December 21, 2010, we may, at our option, cause the Series B Convertible
Preferred Stock to be automatically converted into that number of shares of Common Stock that are
issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may
exercise our conversion right only if, for 20 trading days within any period of 30 consecutive
trading days ending on the trading day prior to the announcement of our exercise of the option, the
closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of
the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is
non-redeemable by us.
We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully
repay all outstanding indebtedness under our senior revolving credit facility. The remaining net
proceeds of the offering were added to our working capital to fund 2006 capital expenditures and
for other general corporate purposes.
On January 23, 2006, the initial purchasers of the Series B Convertible Preferred Stock
exercised their over-allotment option to purchase an additional 600,000 shares at the same price
per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital
expenditure program.
Summary of Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a complete list
in Note 1 Description of Business and Significant Accounting Policies to our consolidated
financial statements.
12
Proved oil and natural gas reserves
Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural
gas liquids and natural gas that geological and engineering data demonstrate with reasonable
certainty are recoverable from known reservoirs under existing economic and operating conditions.
Proved developed reserves are volumes expected to be recovered through existing wells with existing
equipment and operating methods. Although our external engineers are knowledgeable of and follow
the guidelines for reserves as established by the SEC, the estimation of reserves requires the
engineers to make a significant number of assumptions based on professional judgment. Estimated
reserves are often subject to future revision, certain of which could be substantial, based on the
availability of additional information, including: reservoir performance, new geological and
geophysical data, additional drilling, technological advancements, price changes and other economic
factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in
production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to
adjustments of depreciation rates utilized by us. We cannot predict the types of reserve revisions
that will be required in future periods.
Successful efforts accounting
We utilize the successful efforts method to account for exploration and development
expenditures. Unsuccessful exploration wells, as well as other exploration expenditures such as
seismic costs, are expensed and can have a significant effect on operating results. Successful
exploration drilling costs, all development capital expenditures and asset retirement costs are
capitalized and systematically charged to expense using the units of production method based on
proved developed oil and natural gas reserves as estimated by engineers. Certain costs related to
fields or areas that are not fully developed are charged to expense using the units of production
method based on total proved oil and natural gas reserves.
Impairment of properties
We continually monitor our long-lived assets recorded in oil and gas properties in the
Consolidated Balance Sheets to ensure that they are fairly presented. We must evaluate our
properties for potential impairment when circumstances indicate that the carrying value of an asset
could exceed its fair value. Performing these evaluations requires a significant amount of judgment
since the results are based on estimated future events. Such events include a projection of future
oil and natural gas sales prices, an estimate of the
ultimate amount of recoverable proved and probable oil and natural gas reserves that will be
produced from a field, the timing of this future production, future costs to produce the oil and
natural gas, and future inflation levels. The need to test a property for impairment can be based
on several factors, including a significant reduction in sales prices for oil and/or natural gas,
unfavorable adjustments to reserves, or other changes to contracts, environmental regulations or
tax laws. We cannot predict the amount of impairment charges that may be recorded in the future.
Asset retirement obligations
We are required to make estimates of the future costs of the retirement obligations of
our producing oil and gas properties. This requirement necessitates us to make estimates of our
property abandonment costs that, in some cases, will not be incurred until a substantial number of
years in the future. Such cost estimates could be subject to significant revisions in subsequent
years due to changes in regulatory requirements, technological advances and other factors which may
be difficult to predict.
Income taxes
We are subject to income and other related taxes in areas in which we operate. When
recording income tax expense, certain estimates are required by management due to timing and the
impact of future events on when income tax expenses and benefits are recognized by us. We
periodically evaluate our tax operating loss and other carryforwards to determine whether a gross
deferred tax asset, as well as a related valuation allowance, should be recognized in our financial
statements. As of December 31, 2006, and in certain prior years, we have reported a net deferred
tax asset on our Consolidated Balance Sheet, after deduction of the related valuation allowance,
which has been determined on the basis of managements estimation of the likelihood of realization
of the gross deferred tax asset as a deduction against future taxable income.
Derivative Instruments
As discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk, we
periodically utilize derivative instruments to manage both our commodity price risk and interest
rate risk. We consider the use of these instruments to be hedging activities. Pursuant to
derivative accounting rules, we are required to use mark to market accounting to reflect the fair
value of such derivative instruments on our Consolidated Balance Sheet. To the extent that we are
able to demonstrate that our use of derivative instruments qualifies as hedging activities, the
offsetting entry to the changes in fair value of these instruments is accounted for in Other
Comprehensive Income (Loss). To the extent that such derivatives are deemed to be ineffective, the
offsetting entry to the changes in fair value is reflected in earnings.
At the inception of each hedge, we document that the derivative will be highly effective
in offsetting expected changes in cash flows from the item hedged. A hedge must be determined to be
highly effective under accounting rules in order to qualify for hedge accounting treatment. This
assessment, which is updated quarterly, includes an evaluation of the most recent historical
correlation
13
between the derivative and the item hedged. In this analysis, changes in monthly
settlement prices on our oil and gas derivatives are compared with the change in physical daily
indexed prices that we receive from the field purchasers for our oil and gas production designated
for hedging. Should a hedge not be highly effective, it no longer qualifies for hedge accounting
treatment and changes in fair value of the hedge are recognized in earnings.
Price volatility within a measured month is the primary factor affecting the analysis of
effectiveness of our oil and natural gas swaps. Volatility can reduce the correlation between the
hedge settlement price and the price received for physical deliveries. Secondary factors
contributing to changes in pricing differentials include changes in the basis differential which is
the difference in the locally indexed price received for daily physical deliveries of hedged
quantities and the index price used in hedge settlement, and changes in grade and quality factors
of the hedged oil and natural gas production which would further impact the price received for
physical deliveries.
Not withstanding the determination that certain commodity swaps in 2005 and the fourth
quarter of 2006, were not highly effective, management continues to believe that our oil and gas
price hedge strategy has been effective in satisfying our financial objective of providing cash
flow stability.
Our hedge agreements currently consist of (a) swaps, where we receive a fixed price and
pay a floating price, based on NYMEX quoted prices; and (b) collars, where we receive the excess,
if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the
excess, if any, of the reference price over the ceiling price. The terms of our current hedge
agreements are described in Note 8 Hedging Activities to our consolidated financial statements.
Share-Based Compensation Plans
For all new, modified and unvested share-based payment transactions with employees, we
measure at fair value and recognize as compensation expense over the requisite period. The fair
value of each option award is estimated using a Black-Scholes option valuation model that requires
us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses
the following assumptions: expected volatility, expected term of option, risk-free interest rate
and dividend yield. Expected volatility estimates are developed by us based on historical
volatility of our stock. We use historical data to estimate the expected term of the
options. The risk-free interest rate for periods within the expected life of the option is
based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay
dividends; therefore the dividend yield is zero.
New Accounting Pronouncements
See Note 1 Description of Business and Significant Accounting Policies New Accounting
Pronouncements to our consolidated financial statements.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance our liquidity
and capital resource positions, or for any other purpose.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Commodity Price Risk
Despite the measures taken by us to attempt to control price risk, we remain subject to
price fluctuations for natural gas and crude oil sold in the spot market. Prices received for
natural gas sold on the spot market are volatile due primarily to seasonality of demand and other
factors beyond our control. Domestic crude oil and gas prices could have a material adverse effect
on our financial position, results of operations and quantities of reserves recoverable on an
economic basis.
We enter into futures contracts or other hedging agreements from time to time to manage
the commodity price risk for a portion of our production. We consider these agreements to be
hedging activities and, as such, monthly settlements on the contracts that qualify for hedge
accounting are reflected in our crude oil and natural gas sales. Our strategy, which is
administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the
entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of
December 31, 2006, the commodity hedges we utilized were in the form of: (a) swaps, where we
receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars,
where we receive the excess, if any, of the floor price over the reference price, based on NYMEX
quoted prices, and pay the excess, if any, of the reference price over the ceiling price. See Note
8 Hedging Activities to our consolidated financial statements for additional information.
Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net
oil and gas production volumes for the applicable periods of 2006. The fair value of the crude oil
and natural gas hedging contracts in place at December 31, 2006, resulted in an asset of $13.4
million. Based on oil and gas pricing in effect at December 31, 2006, a hypothetical 10% increase
in oil and gas prices would have decreased the derivative asset to $11.9 million while a
hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to $14.9
million.
14
Interest Rate Risk
We have a variable-rate debt obligation that exposes us to the effects of changes in
interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter
into interest rate swap agreements. At December 31, 2006, we had the following interest rate swaps
in place with BNP (in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective |
|
|
|
Maturity |
|
LIBOR |
|
Notional |
Date |
|
|
|
Date |
|
Swap Rate |
|
Amount |
|
02/27/06 |
|
|
|
|
|
02/26/07 |
|
|
|
4.08 |
% |
|
|
23.0 |
|
|
02/27/06 |
|
|
|
|
|
02/26/07 |
|
|
|
4.85 |
% |
|
|
17.0 |
|
|
02/27/07 |
|
|
|
|
|
02/26/09 |
|
|
|
4.86 |
% |
|
|
40.0 |
|
The fair value of the interest rate swap contracts in place at December 31, 2006,
resulted in an asset of $0.2 million. Based on interest rates at December 31, 2006, a hypothetical
10% increase or decrease in interest rates would not have a material effect on the asset.
15
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Goodrich Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Goodrich Petroleum
Corporation and Subsidiaries as of December 31, 2006 and 2005, and the related consolidated
statements of operations, cash flows, stockholders equity and comprehensive income (loss) for each
of the years in the three-year period ended December 31, 2006. These consolidated financial
statements are the responsibility of the Companys management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of Goodrich Petroleum Corporation and Subsidiaries
as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each
of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally
accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, effective January 1,
2006, the Company changed its method of accounting for share based payments.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Goodrich Petroleum Corporations internal
control over financial reporting as of December 31, 2006, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 14, 2007 expressed an unqualified opinion on
managements assessment of, and the effective operation of, internal control over financial
reporting.
KPMG LLP
New Orleans, Louisiana
March 14, 2007
except for the effects of discontinued operations, as discussed in Note 12, which is as of August 6, 2007
16
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands, Except Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
6,184 |
|
|
$ |
19,842 |
|
Accounts receivable, trade and other, net of allowance |
|
|
9,665 |
|
|
|
6,397 |
|
Accrued oil and gas revenue |
|
|
10,689 |
|
|
|
11,863 |
|
Fair value of oil and gas derivatives |
|
|
13,419 |
|
|
|
|
|
Fair value of interest rate derivatives |
|
|
219 |
|
|
|
107 |
|
Prepaid expenses and other |
|
|
994 |
|
|
|
463 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
41,170 |
|
|
|
38,672 |
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and gas properties (successful efforts method) |
|
|
575,666 |
|
|
|
316,286 |
|
Furniture, fixtures and equipment |
|
|
1,463 |
|
|
|
1,075 |
|
|
|
|
|
|
|
|
|
|
|
577,129 |
|
|
|
317,361 |
|
Less: Accumulated depletion, depreciation and amortization |
|
|
(156,509 |
) |
|
|
(74,229 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
420,620 |
|
|
|
243,132 |
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
Restricted cash and investments |
|
|
2,039 |
|
|
|
2,039 |
|
Deferred tax asset |
|
|
9,705 |
|
|
|
11,580 |
|
Other |
|
|
5,730 |
|
|
|
1,103 |
|
|
|
|
|
|
|
|
Total other assets |
|
|
17,474 |
|
|
|
14,722 |
|
|
|
|
|
|
|
|
TOTAL ASSETS |
|
$ |
479,264 |
|
|
$ |
296,526 |
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
36,263 |
|
|
$ |
31,574 |
|
Accrued liabilities |
|
|
26,811 |
|
|
|
15,973 |
|
Fair value of oil and gas derivatives |
|
|
|
|
|
|
23,271 |
|
Accrued abandonment costs |
|
|
263 |
|
|
|
92 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
63,337 |
|
|
|
70,910 |
|
LONG-TERM DEBT |
|
|
201,500 |
|
|
|
30,000 |
|
Accrued abandonment costs |
|
|
9,294 |
|
|
|
7,868 |
|
Fair value of oil and gas derivatives |
|
|
|
|
|
|
6,159 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
274,131 |
|
|
|
114,937 |
|
|
|
|
|
|
|
|
Commitments and contingencies (See Note 10) |
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY: |
|
|
|
|
|
|
|
|
Preferred stock: 10,000,000 shares authorized: |
|
|
|
|
|
|
|
|
Series A convertible preferred stock, $1.00 par value,
issued and outstanding none and 791,968 shares, respectively |
|
|
|
|
|
|
792 |
|
Series B convertible preferred stock, $1.00 par value,
issued and outstanding 2,250,000 and 1,650,000 shares, respectively |
|
|
2,250 |
|
|
|
1,650 |
|
Common stock: $0.20 par value, 50,000,000 shares authorized;
issued and outstanding 28,218,422 and 24,804,737 shares, respectively |
|
|
5,049 |
|
|
|
4,961 |
|
Additional paid in capital |
|
|
213,666 |
|
|
|
187,967 |
|
Accumulated deficit |
|
|
(14,571 |
) |
|
|
(8,649 |
) |
Unamortized restricted stock awards |
|
|
|
|
|
|
(2,066 |
) |
Accumulated other comprehensive loss |
|
|
(1,261 |
) |
|
|
(3,066 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
205,133 |
|
|
|
181,589 |
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND
STOCKHOLDERS EQUITY |
|
$ |
479,264 |
|
|
$ |
296,526 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
17
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues |
|
$ |
73,933 |
|
|
$ |
34,986 |
|
|
$ |
3,759 |
|
Other |
|
|
838 |
|
|
|
325 |
|
|
|
151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74,771 |
|
|
|
35,311 |
|
|
|
3,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating expense |
|
|
13,182 |
|
|
|
3,821 |
|
|
|
347 |
|
Production taxes |
|
|
2,851 |
|
|
|
1,809 |
|
|
|
164 |
|
Transportation |
|
|
3,791 |
|
|
|
558 |
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
37,225 |
|
|
|
12,214 |
|
|
|
1,486 |
|
Exploration |
|
|
5,888 |
|
|
|
5,697 |
|
|
|
955 |
|
Impairment of oil and gas properties |
|
|
9,886 |
|
|
|
340 |
|
|
|
|
|
General and administrative |
|
|
17,223 |
|
|
|
8,622 |
|
|
|
5,821 |
|
Gain on sale of assets |
|
|
(23 |
) |
|
|
(235 |
) |
|
|
(50 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
90,023 |
|
|
|
32,826 |
|
|
|
8,723 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(15,252 |
) |
|
|
2,485 |
|
|
|
(4,813 |
) |
|
|
|
|
|
|
|
|
|
|
OTHER INCOME AND (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(7,845 |
) |
|
|
(2,359 |
) |
|
|
(1,110 |
) |
Gain (loss) on derivatives not qualifying for hedge accounting |
|
|
38,128 |
|
|
|
(37,680 |
) |
|
|
2,317 |
|
Loss on early extinguishment of debt |
|
|
(612 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,671 |
|
|
|
(40,039 |
) |
|
|
1,207 |
|
|
|
|
|
|
|
|
|
|
|
INCOME
(LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
|
|
14,419 |
|
|
|
(37,554 |
) |
|
|
(3,606 |
) |
INCOME TAX (EXPENSE) BENEFIT |
|
|
(5,120 |
) |
|
|
13,144 |
|
|
|
8,594 |
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM CONTINUING OPERATIONS |
|
|
9,299 |
|
|
|
(24,410 |
) |
|
|
4,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations including gain on sale of assets, net of tax |
|
|
(7,660 |
) |
|
|
6,960 |
|
|
|
13,539 |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
|
1,639 |
|
|
|
(17,450 |
) |
|
|
18,527 |
|
PREFERRED STOCK DIVIDENDS |
|
|
6,016 |
|
|
|
755 |
|
|
|
633 |
|
PREFERRED STOCK REDEMPTION PREMIUM |
|
|
1,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK |
|
$ |
(5,922 |
) |
|
$ |
(18,205 |
) |
|
$ |
17,894 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) PER COMMON SHARE-BASIC |
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM CONTINUING OPERATIONS |
|
$ |
0.37 |
|
|
$ |
(1.05 |
) |
|
$ |
0.26 |
|
DISCONTINUED OPERATIONS |
|
$ |
(0.30 |
) |
|
$ |
0.30 |
|
|
$ |
0.69 |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
$ |
0.07 |
|
|
$ |
(0.75 |
) |
|
$ |
0.95 |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK |
|
$ |
(0.24 |
) |
|
$ |
(0.78 |
) |
|
$ |
0.92 |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) PER COMMON SHARE-DILUTED |
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) FROM CONTINUING OPERATIONS |
|
$ |
0.37 |
|
|
$ |
(1.05 |
) |
|
$ |
0.25 |
|
DISCONTINUED OPERATIONS |
|
$ |
(0.31 |
) |
|
$ |
0.30 |
|
|
$ |
0.66 |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
$ |
0.06 |
|
|
$ |
(0.75 |
) |
|
$ |
0.91 |
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK |
|
$ |
(0.24 |
) |
|
$ |
(0.78 |
) |
|
$ |
0.88 |
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-BASIC |
|
|
24,948 |
|
|
|
23,333 |
|
|
|
19,552 |
|
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-DILUTED |
|
|
25,412 |
|
|
|
23,333 |
|
|
|
20,347 |
|
See accompanying notes to consolidated financial statements
18
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss) |
|
$ |
1,639 |
|
|
$ |
(17,450 |
) |
|
$ |
18,527 |
|
Adjustments to reconcile net income (loss) to net cash provided
by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and amortization |
|
|
52,642 |
|
|
|
25,563 |
|
|
|
11,717 |
|
Unrealized (gain) loss on derivatives not qualifying for
hedge accounting |
|
|
(40,185 |
) |
|
|
26,960 |
|
|
|
(2,317 |
) |
Deferred income taxes |
|
|
904 |
|
|
|
(9,396 |
) |
|
|
(1,303 |
) |
Dry hole costs |
|
|
7,926 |
|
|
|
2,014 |
|
|
|
|
|
Amortization of leasehold costs |
|
|
5,488 |
|
|
|
3,344 |
|
|
|
1,035 |
|
Impairment of oil and gas properties |
|
|
24,790 |
|
|
|
340 |
|
|
|
|
|
Stock based compensation (non-cash) |
|
|
5,962 |
|
|
|
1,383 |
|
|
|
1,031 |
|
Loss on early extinguishment of debt |
|
|
612 |
|
|
|
|
|
|
|
|
|
Gain on sale of assets |
|
|
(23 |
) |
|
|
(235 |
) |
|
|
(814 |
) |
Other non-cash items |
|
|
476 |
|
|
|
(156 |
) |
|
|
(967 |
) |
Change in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, trade and other, net of allowance |
|
|
(3,268 |
) |
|
|
786 |
|
|
|
(3,683 |
) |
Accrued oil and gas revenue |
|
|
1,174 |
|
|
|
(8,741 |
) |
|
|
(293 |
) |
Prepaid expenses and other |
|
|
(531 |
) |
|
|
169 |
|
|
|
(280 |
) |
Accounts payable |
|
|
4,689 |
|
|
|
8,222 |
|
|
|
16,644 |
|
Accrued liabilities |
|
|
2,838 |
|
|
|
12,759 |
|
|
|
1,731 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
65,133 |
|
|
|
45,562 |
|
|
|
41,028 |
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(261,435 |
) |
|
|
(164,551 |
) |
|
|
(47,501 |
) |
Proceeds from sale of assets |
|
|
2,698 |
|
|
|
980 |
|
|
|
2,087 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(258,737 |
) |
|
|
(163,571 |
) |
|
|
(45,414 |
) |
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Principal payments of bank borrowings |
|
|
(184,500 |
) |
|
|
(118,500 |
) |
|
|
(1,000 |
) |
Proceeds from bank borrowings |
|
|
181,000 |
|
|
|
121,500 |
|
|
|
8,000 |
|
Proceeds from convertible note offering |
|
|
175,000 |
|
|
|
|
|
|
|
|
|
Net proceeds from common stock offering |
|
|
|
|
|
|
53,112 |
|
|
|
|
|
Net proceeds from preferred stock offering |
|
|
28,973 |
|
|
|
79,775 |
|
|
|
|
|
Redemption of preferred stock |
|
|
(9,319 |
) |
|
|
|
|
|
|
|
|
Exercise of stock options and warrants |
|
|
406 |
|
|
|
477 |
|
|
|
340 |
|
Production payments |
|
|
|
|
|
|
(297 |
) |
|
|
(361 |
) |
Deferred financing costs |
|
|
(5,598 |
) |
|
|
(971 |
) |
|
|
|
|
Preferred stock dividends |
|
|
(6,016 |
) |
|
|
(634 |
) |
|
|
(633 |
) |
Other |
|
|
|
|
|
|
(60 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
179,946 |
|
|
|
134,402 |
|
|
|
6,346 |
|
|
|
|
|
|
|
|
|
|
|
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
|
|
(13,658 |
) |
|
|
16,393 |
|
|
|
1,960 |
|
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD |
|
|
19,842 |
|
|
|
3,449 |
|
|
|
1,489 |
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, END OF PERIOD |
|
$ |
6,184 |
|
|
$ |
19,842 |
|
|
$ |
3,449 |
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION |
|
|
|
|
|
|
|
|
|
|
|
|
CASH PAID DURING THE YEAR FOR INTEREST |
|
$ |
7,284 |
|
|
$ |
1,862 |
|
|
$ |
865 |
|
|
|
|
|
|
|
|
|
|
|
CASH PAID DURING THE YEAR FOR INCOME TAXES |
|
$ |
|
|
|
$ |
110 |
|
|
$ |
30 |
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to consolidated financial statements.
19
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
Series A Preferred Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
792 |
|
|
$ |
792 |
|
|
|
792 |
|
|
$ |
792 |
|
|
|
792 |
|
|
$ |
792 |
|
Offering of preferred stock |
|
|
(792 |
) |
|
|
(792 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
|
|
|
$ |
|
|
|
|
792 |
|
|
$ |
792 |
|
|
|
792 |
|
|
$ |
792 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series B Preferred Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
1,650 |
|
|
$ |
1,650 |
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
Offering of preferred stock |
|
|
|
|
|
|
|
|
|
|
1,650 |
|
|
|
1,650 |
|
|
|
|
|
|
|
|
|
Issuance of preferred stock |
|
|
600 |
|
|
|
600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
2,250 |
|
|
$ |
2,250 |
|
|
|
1,650 |
|
|
$ |
1,650 |
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
24,805 |
|
|
$ |
4,961 |
|
|
|
20,587 |
|
|
$ |
4,117 |
|
|
|
18,130 |
|
|
$ |
3,626 |
|
Offering of common stock |
|
|
|
|
|
|
|
|
|
|
3,710 |
|
|
|
742 |
|
|
|
|
|
|
|
|
|
Redemption of Series A preferred stock |
|
|
6 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of
and amortization of restricted stock |
|
|
182 |
|
|
|
36 |
|
|
|
123 |
|
|
|
25 |
|
|
|
52 |
|
|
|
10 |
|
Exercise of stock options and warrants |
|
|
66 |
|
|
|
44 |
|
|
|
371 |
|
|
|
74 |
|
|
|
2,376 |
|
|
|
475 |
|
Director stock grants |
|
|
37 |
|
|
|
7 |
|
|
|
14 |
|
|
|
3 |
|
|
|
29 |
|
|
|
6 |
|
Shares pursuant to share lending agreement |
|
|
3,122 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
28,218 |
|
|
$ |
5,049 |
|
|
|
24,805 |
|
|
$ |
4,961 |
|
|
|
20,587 |
|
|
$ |
4,117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paid in Capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
|
|
|
$ |
187,967 |
|
|
|
|
|
|
$ |
55,409 |
|
|
|
|
|
|
$ |
53,359 |
|
Offering of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52,370 |
|
|
|
|
|
|
|
|
|
Offering of preferred stock |
|
|
|
|
|
|
28,373 |
|
|
|
|
|
|
|
78,125 |
|
|
|
|
|
|
|
|
|
Redemption of Series A preferred stock |
|
|
|
|
|
|
(6,983 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of
and amortization of restricted stock |
|
|
|
|
|
|
2,205 |
|
|
|
|
|
|
|
1,423 |
|
|
|
|
|
|
|
1,951 |
|
Reclassification from unamortized restricted
stock upon adoption of FAS 123R |
|
|
|
|
|
|
(2,066 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation |
|
|
|
|
|
|
2,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options and warrants |
|
|
|
|
|
|
295 |
|
|
|
|
|
|
|
403 |
|
|
|
|
|
|
|
(135 |
) |
Director stock grants |
|
|
|
|
|
|
1,388 |
|
|
|
|
|
|
|
237 |
|
|
|
|
|
|
|
234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
|
|
|
$ |
213,666 |
|
|
|
|
|
|
$ |
187,967 |
|
|
|
|
|
|
$ |
55,409 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained Earnings(Deficit) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
|
|
|
|
(8,649 |
) |
|
|
|
|
|
|
9,556 |
|
|
|
|
|
|
|
(8,338 |
) |
Net income(loss) |
|
|
|
|
|
|
1,639 |
|
|
|
|
|
|
|
(17,450 |
) |
|
|
|
|
|
|
18,527 |
|
Redemption of Series A preferred stock |
|
|
|
|
|
|
(1,545 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend |
|
|
|
|
|
|
(6,016 |
) |
|
|
|
|
|
|
(755 |
) |
|
|
|
|
|
|
(633 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
|
|
|
$ |
(14,571 |
) |
|
|
|
|
|
$ |
(8,649 |
) |
|
|
|
|
|
$ |
9,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unamortized Restricted Stock Awards |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
|
|
|
$ |
(2,066 |
) |
|
|
|
|
|
|
(1,762 |
) |
|
|
|
|
|
|
(382 |
) |
Issuance of
and amortization of restricted stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(304 |
) |
|
|
|
|
|
|
(1,380 |
) |
Reclassification to APIC upon adoption of FAS 123R |
|
|
|
|
|
|
2,066 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
(2,066 |
) |
|
|
|
|
|
$ |
(1,762 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive Loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
|
|
|
|
$ |
(3,066 |
) |
|
|
|
|
|
$ |
(2,805 |
) |
|
|
|
|
|
$ |
(998 |
) |
Other comprehensive loss |
|
|
|
|
|
|
1,805 |
|
|
|
|
|
|
|
(261 |
) |
|
|
|
|
|
|
(1,807 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
|
|
|
$ |
(1,261 |
) |
|
|
|
|
|
$ |
(3,066 |
) |
|
|
|
|
|
$ |
(2,805 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders Equity at December 31, |
|
|
|
|
|
$ |
205,133 |
|
|
|
|
|
|
$ |
181,589 |
|
|
|
|
|
|
$ |
65,307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
20
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Net income (loss) |
|
$ |
1,639 |
|
|
$ |
(17,450 |
) |
|
$ |
18,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives (1) |
|
|
(1,025 |
) |
|
|
(6,233 |
) |
|
|
(5,909 |
) |
Reclassification adjustment (2) |
|
|
2,830 |
|
|
|
5,972 |
|
|
|
4,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,805 |
|
|
|
(261 |
) |
|
|
(1,807 |
) |
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) |
|
$ |
3,444 |
|
|
$ |
(17,711 |
) |
|
$ |
16,720 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Net of income tax benefit of: |
|
$ |
552 |
|
|
$ |
3,356 |
|
|
$ |
3,180 |
|
(2) Net of income tax expense of: |
|
$ |
1,524 |
|
|
$ |
3,216 |
|
|
$ |
2,209 |
|
See accompanying notes to consolidated financial statements.
21
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1Description of Business and Significant Accounting Policies
We are in the primary business of exploration and production of crude oil and natural
gas. We and our subsidiaries have interests in such operations in three states, primarily in Texas
and Louisiana.
Principles of ConsolidationThe consolidated financial statements include the financial
statements of Goodrich Petroleum Corporation and its wholly-owned subsidiaries. Significant
intercompany balances and transactions have been eliminated in consolidation. Certain
reclassifications have been made to the prior year statements to conform to the current year
presentation.
Use of EstimatesOur Management has made a number of estimates and assumptions relating
to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent
assets and liabilities to prepare these consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America. Actual results could
differ from those estimates.
Cash and Cash EquivalentsCash and cash equivalents include cash on hand, demand deposit
accounts and temporary cash investments with maturities of ninety days or less at date of purchase.
Restricted cash represents amounts held in escrow for plugging and abandonment obligations which
were incurred with the acquisition of our Burrwood and West Delta 83 fields in 2000.
Revenue RecognitionRevenues from the production of crude oil and natural gas properties
in which we have an interest with other producers are recognized on the entitlements method. We
record an asset or liability for natural gas balancing when we have purchased or sold more than our
working interest share of natural gas production, respectively. At December 31, 2006 and 2005, the
net assets for gas balancing were $1.5 million and $0.7 million, respectively. Differences between
actual production and net working interest volumes are routinely adjusted. These differences are
not significant.
Property and EquipmentWe use the successful efforts method of accounting for exploration
and development expenditures. Leasehold acquisition costs are capitalized. When proved reserves are
found on an undeveloped property, leasehold cost is reclassified to proved properties. Significant
undeveloped leases are reviewed periodically, and a valuation allowance is provided for any
estimated decline in value. Cost of all other undeveloped leases is amortized over the estimated
average holding period of the leases.
Costs of exploratory drilling are initially capitalized, but if proved reserves are not
found the costs are subsequently expensed. All other exploratory costs are charged to expense as
incurred. Development costs are capitalized, including the cost of unsuccessful development wells.
We recognize an impairment when the net of future cash inflows expected to be generated
by an identifiable long-lived asset and cash outflows expected to be required to obtain those cash
inflows is less than the carrying value of the asset. We perform this comparison for our oil and
gas properties on a field-by-field basis using our estimates of future commodity prices and proved
and probable reserves. The amount of such loss is measured based on the difference between the
discounted value of such net future cash flows and the carrying value of the asset. For the years
ended December 31, 2006 and 2005, we recorded impairments on continuing operations of $9.9 million
and $0.3 million, respectively, as a result of certain non-core fields depleting earlier than
anticipated. There were no impairments in 2004.
Depreciation and depletion of producing oil and gas properties are provided under the
unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized
tangible and intangible development costs, and proved reserves are used for unamortized leasehold
costs. As described in Note 3, we follow the provisions of Statement of Financial Accounting
Standards (SFAS) No. 143, Accounting for Asset
Retirement Obligations (SFAS 143). Our asset retirement obligations are amortized based
upon units of production of proved reserves attributable to the properties to which the obligations
relate. Some of these obligations relate to an individual producing well or group of producing
wells and are amortized based on proved developed reserves attributable to that well or group of
wells. Other asset retirement obligations may relate to an entire field or area that is not fully
developed. Because these obligations relate to assets installed to service future development, they
are amortized based on all proved reserves attributable to the field or area.
Gains and losses on disposals or retirements that are significant or include an entire
depreciable or depletable property unit are included in income. All other dispositions,
retirements, or abandonments are reflected in accumulated depreciation, depletion, and
amortization.
22
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Furniture, fixtures and equipment consists of office furniture, computer hardware and
software and leasehold improvements. Depreciation of these assets is computed using the
straight-line method over their estimated useful lives, which vary from one to five years.
Income TaxesWe follow the provisions of SFAS No. 109, Accounting for Income Taxes,
(SFAS 109) which requires income taxes be accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable income in the years
in which those temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rates is recognized in income in the period
that includes the enactment date.
Earnings Per ShareBasic income per common share is computed by dividing net income
available for common stockholders, for each reporting period by the weighted average number of
common shares outstanding during the period. Diluted income per common share is computed by
dividing net income available for common stockholders for each reporting period by the weighted
average number of common shares outstanding during the period, plus the effects of potentially
dilutive common shares.
Derivative Instruments and Hedging ActivitiesWe utilize derivative instruments such as
futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations
in the price of crude oil and natural gas and to hedge our exposure to changing interest rates.
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as
amended, requires that all derivative instruments subject to the requirements of the statement be
measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering
into a derivative contract, we may designate the derivative as either a fair value hedge or a cash
flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to
market through earnings. We document the relationship between the derivative instrument designated
as a hedge and the hedged items, as well as our objective for risk management and strategy for use
of the hedging instrument to manage the risk. Derivative instruments designated as fair value or
cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or
forecasted transactions. We assess at inception, and on an ongoing basis, whether a derivative
instrument used as a hedge is highly effective in offsetting changes in the fair value or cash
flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for
hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in
earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying
cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash
flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of
Operations, the fair value of the associated cash flow hedge is reclassified from other
comprehensive income into earnings.
Ineffective portions of a cash flow hedging derivatives change in fair value are
recognized currently in earnings as other income (expense). If a derivative instrument no longer
qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was
recorded in other comprehensive income is recognized over the period anticipated in the original
hedge transaction.
Asset Retirement ObligationsWe follow SFAS 143 (see Note 3) which applies to obligations
associated with the retirement of tangible long-lived assets that result from the acquisition,
construction and development of the assets. SFAS 143 requires that we record the fair value of a
liability for an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Commitments and ContingenciesLiabilities for loss contingencies, including environmental
remediation costs, arising from claims, assessments, litigation, fines and penalties, and other
sources are recorded when it is probable that a liability has been incurred and the amount of the
assessment and/or remediation can be reasonably estimated. Recoveries from third parties, which are
probable of realization, are separately recorded, and are not offset against the related
environmental liability.
Concentration of Credit RiskDue to the nature of the industry, we sell our oil and
natural gas production to a limited number of purchasers and, accordingly, amounts receivable from
such purchasers could be significant. Revenues from two purchasers accounted for 35% and 15% of oil
and gas revenues for the year ended December 31, 2006. For the year ended December 31, 2005,
revenue from three purchasers accounted for 34%, 18% and 13% of oil and gas revenues. For the year
ended December 31, 2004, revenues from two purchasers accounted for 45% and 15%, of oil and gas.
23
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Share-Based Compensation Plans. In December 2004, the FASB issued SFAS No. 123 (revised 2004),
Share-Based Payment (SFAS 123R), replacing SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS 123), and superseding Accounting Principles Board (APB) Opinion No. 25,
Accounting for Stock Issued to Employees (APB 25). In January 2006, we adopted SFAS 123R which
replaces SFAS 123 and supersedes APB 25. SFAS 123R requires new, modified and unvested share-based
payment transactions with employees to be measured at fair value and recognized as compensation
expense over the requisite service period. The fair value of each option award is estimated using a
Black-Scholes option valuation model that requires us to develop estimates for assumptions used in
the model. The Black-Scholes valuation model uses the following assumptions: expected volatility,
expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates
are developed by us based on historical volatility of our stock. We use historical data to estimate
the expected term of the options. The risk-free interest rate for periods within the expected life
of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock
does not pay dividends; therefore the dividend yield is zero. See Note 2.
New Accounting Pronouncements In February 2007, the Financial Accounting Standards Board
(FASB) issued SFAS 159, The Fair Value Option for Financial Assets and Financial
Liabilitiesincluding an amendment of FASB Statement No. 115, which allows measurement at fair
value of eligible financial assets and liabilities that are not otherwise measured at fair value.
If the fair value option for an eligible item is elected, unrealized gains and losses for that item
shall be reported in current earnings at each subsequent reporting date. SFAS 159 also establishes
presentation and disclosure requirements designed to draw comparison between the different
measurement attributes the company elects for similar types of assets and liabilities. SFAS 159 is
effective for fiscal years beginning after November 15, 2007. Early adoption is permitted. We are
currently assessing the impact of SFAS 159 on our financial statements.
In September 2006, the Securities and Exchange Commission issued Staff Accounting
Bulletin No. 108 (SAB 108), which became effective for fiscal years ending after November 15,
2006. SAB 108 provides guidance on the consideration of the effects of prior period misstatements
in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108
requires an entity to evaluate the impact of correcting all misstatements, including both the
carryover and reversing effects of prior year misstatements, on current year financial statements.
If a misstatement is material to the current year financial statements, the prior year financial
statements should also be corrected, even though such revision was, and continues to be, immaterial
to the prior year financial statements. Correcting prior year financial statements for immaterial
errors would not require previously filed reports to be amended. Such correction should be made in
the current period filings. The adoption of this standard at December 31, 2006 had no impact on the
companys financial statements.
In December 2006, FASB issued a FASB Staff Position (FSP) EITF 00-19-2 Accounting for
Registration Payment Arrangements (FSP 00-19-2). This FSP addresses an issuers accounting for
registration payment arrangements. This FSP specifies that the contingent obligation to make future
payments or otherwise transfer consideration under a registration payment arrangement, whether
issued as a separate agreement or included as a provision of a financial instrument or other
agreement, should be separately recognized and measured in accordance with FASB Statement No. 5
Accounting for Contingencies. The guidance in this FSP amends FASB Statements No. 133,
Accounting for Derivative Instruments and Hedging Activities, and No. 150, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and Equity, as well as FASB
Interpretation No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others to include scope exceptions for
registration payment arrangements. This FSP is effective immediately for registration payment
arrangements and the financial instruments subject to those arrangements that are entered into or
modified subsequent to the date of issuance of this FSP. For registration payment arrangements and
financial instruments subject to those arrangements that were entered into prior to the issuance of
this FSP, this is effective for financial statements issued for fiscal years beginning after
December 15, 2006, and interim periods within those fiscal years. We are currently evaluating the
impact that the implementation of FSP EITF 00-19-2 may have in our consolidated results of
operations and financial position.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157),
which defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. This Statement applies
under other accounting pronouncements that require or permit fair value measurements, the FASB
having previously concluded in those accounting pronouncements that fair value is the relevant
measurement attribute. Accordingly, this Statement does not require any new fair value
measurements. SFAS 157 is effective for fiscal years beginning after December 15, 2007. We plan to
adopt SFAS 157 beginning in the first quarter of fiscal 2008. We are currently evaluating the
impact, if any, the adoption of SFAS 157 will have on our consolidated financial position, results
of operations or cash flows.
24
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
In July 2006, the FASB issued Financial Interpretation No. 48, Accounting for
Uncertainty in Income Taxesan interpretation of FASB Statement No. 109 (FIN 48). FIN 48, which
clarifies SFAS 109, establishes the criterion that an individual tax position has to meet for some
or all of the benefits of that position to be recognized in our consolidated financial statements.
On initial application, FIN 48 will be applied to all tax positions for which the statute of
limitations remains open. Only tax positions that meet the more-likely-than-not recognition
threshold at the adoption date will be recognized or continue to be recognized. The cumulative
effect of applying FIN 48 will be reported as an adjustment to retained earnings at the beginning
of the period in which it is adopted. FIN 48 is effective for fiscal years beginning after December
15, 2006, and we plan to adopt FIN 48 on January 1, 2007. We do not expect that the adoption of FIN
48 will have a significant effect on our consolidated financial statements or our ability to comply
with our current debt covenants.
In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial
Assets (SFAS 156), which requires all separately recognized servicing assets and servicing
liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the
subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is
required as of the beginning of the first fiscal year that begins after September 15, 2006. The
adoption of SFAS 156 is not expected to have a material effect on our consolidated financial
position, results of operations or cash flows.
In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial
Instruments, an amendment of FASB Statements No. 133 and 140 (SFAS 155). SFAS 155 clarifies
certain issues relating to embedded derivatives and beneficial interests in securitized financial
assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued
after fiscal years beginning after September 15, 2006. We are currently assessing the impact that
the adoption of SFAS 155 will have on our consolidated financial position, results of operations or
cash flows.
We do not believe that any other recently issued, but not yet effective accounting
pronouncements, if adopted, would have a material effect on our accompanying financial statements.
NOTE 2Stock-Based Compensation
Share-Based Employee Compensation Plans
Stock Option and Incentive Programs
We have historically had two plans, which provide for stock option and other incentive
awards for our key employees, consultants and directors: (a) the Goodrich Petroleum Corporation
1995 Stock Option Plan (the 1995 Plan), which allowed grants of stock options, restricted stock
awards, stock appreciation rights, long-term incentive awards and phantom stock awards, or any
combination thereof, to key employees and consultants, and (b) the Goodrich Petroleum Corporation
1997 Director Compensation Plan (the Directors Plan), which allowed grants of stock and options
to each director who is not and has never been an employee of the Company. The Goodrich Petroleum
Corporation 1995 Stock Option Plan expired according to its original terms in late 2005; however,
our Board of Directors approved the extension of the 1995 Plan through December 31, 2005 and the
granting of a total of 525,000 stock options at an exercise price of $23.39 and 101,129 shares of
restricted stock to certain of our employees and officers as of December 6, 2005, subject to
approval at our 2006 Annual Meeting of Stockholders. As of February 9, 2006, our directors and
executive officers reached a level of more than 50% ownership of our total shares of Common Stock
outstanding; therefore, stockholder approval of these actions was no longer contingent. For
accounting purposes, we began expensing the December 6, 2005 grants based on the grant date value
as determined under SFAS 123R, which utilizes the closing price of our Common Stock as of February
9, 2006. At our 2006 Annual Meeting of Stockholders, a proposal to implement a new combined plan to
replace both the Goodrich Petroleum Corporation 1995 Stock Option Plan and the Goodrich Petroleum
Corporation 1997 Director Compensation Plan was approved.
Prior to the expiration of the 1995 Stock Option Plan, the two Goodrich plans had
authorized grants of options to purchase up to a combined total of 2,300,000 shares of authorized
but unissued common stock. Stock options under both plans were granted with an exercise price equal
to the stocks fair market value at the date of grant, and all employee stock options granted under
the 1995 Stock Option Plan generally had ten year terms and three year pro rata vesting. Share
options granted under the Director Plan generally became exercisable immediately and expire, if not
exercised, ten years thereafter.
In May 2006, our shareholders approved our 2006 Long-Term Incentive Plan (the 2006
Plan), at our annual meeting of stockholders. The 2006 Plan is similar to and replaces our
previously adopted 1995 Incentive Plan (the 1995 Plan) and 1997 Non-Employee
Directors Stock Option Plan (the Directors Plan). No further awards will be granted under the
previously adopted plans, however, those plans shall continue to apply to and govern awards made
thereunder.
25
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Under the 2006 Plan, a maximum of 2.0 million new shares are reserved for issuance as awards
of share options to officers, employees and non-employee directors. Share options granted to
officers and employees will generally become exercisable in one-third increments over a three year
period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share
options granted to non-employee directors will usually be immediately exercisable and to the extent
not exercised, expire on the tenth anniversary of the date of grant. The exercise price of share
options granted under the 2006 Plan will equal the market value of the underlying stock on the date
of grant.
At December 31, 2006, options to purchase 100,000 shares of our common stock were
outstanding under the 2006 Plan and options to purchase 923,500 shares of our common stock were
outstanding under the 1995 Plan and the Directors Plan. In order to satisfy share option
exercises, shares are issued from authorized but unissued common stock.
A summary of stock option activity is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
|
|
Remaining |
|
|
Number of |
|
Exercise |
|
Range of |
|
Contractual |
|
|
Options |
|
Price |
|
Exercise Price |
|
Life |
Outstanding, January 1, 2004 |
|
|
236,813 |
|
|
|
|
|
|
$ |
0.75 to $5.85 |
|
|
7.7 yrs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted1995 stock option plan |
|
|
220,000 |
|
|
|
16.46 |
|
|
|
|
|
|
|
|
|
Exercised1995 stock option plan |
|
|
(2,750 |
) |
|
|
2.90 |
|
|
|
|
|
|
|
|
|
Exercised1997 director compensation plan |
|
|
(43,563 |
) |
|
|
3.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2004 |
|
|
410,500 |
|
|
|
|
|
|
$ |
0.75 to $16.46 |
|
|
8.5 yrs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted1997 director compensation plan |
|
|
150,000 |
|
|
|
19.78 |
|
|
|
|
|
|
|
|
|
Exercised1995 stock option plan |
|
|
(25,000 |
) |
|
|
2.88 |
|
|
|
|
|
|
|
|
|
Exercised1997 director compensation plan |
|
|
(16,000 |
) |
|
|
4.92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2005 |
|
|
519,500 |
|
|
|
13.70 |
|
|
$ |
0.75 to $19.78 |
|
|
8.4 yrs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted2006 stock option plan |
|
|
625,000 |
|
|
|
24.10 |
|
|
|
|
|
|
|
|
|
Exercised1995 stock option plan |
|
|
(66,000 |
) |
|
|
7.23 |
|
|
|
|
|
|
|
|
|
Forfeited1995 stock option plan |
|
|
(55,000 |
) |
|
|
22.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, December 31, 2006 |
|
|
1,023,500 |
|
|
|
20.01 |
|
|
$ |
.75 to $27.81 |
|
|
8.2 yrs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2004 |
|
|
169,500 |
|
|
|
3.20 |
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2005 |
|
|
372,100 |
|
|
|
12.60 |
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2006 |
|
|
492,167 |
|
|
|
16.36 |
|
|
|
|
|
|
|
|
|
Adoption of New Accounting Pronouncement
Effective January 1, 2006 we adopted SFAS 123R, which required us to measure the cost of
stock based compensation granted, including stock options and restricted stock, based on the fair
market value of the award as of the grant date, net of estimated forfeitures. SFAS 123R supersedes
SFAS 123 and APB 25. We adopted SFAS 123R using the modified prospective application method of
adoption, which required us to record compensation cost related to unvested stock awards as of
December 31, 2005, by recognizing the unamortized grant date fair value of these awards over the
remaining service periods of those awards with no change in historical reported earnings. Awards
granted after December 31, 2005, are valued at fair value in accordance with provisions of SFAS
123R and recognized on a straight line basis over the service periods of each award. We estimated
forfeiture rates for all unvested awards based on our historical experience. The January 1, 2006,
26
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
balance of unamortized restricted stock awards of $2.1 million was reclassified against
additional paid-in-capital upon adoption of SFAS 123R. In fiscal 2006 and future periods, common
stock par value will be recorded when the restricted stock is issued and additional paid-in-capital
will be increased as the restricted stock compensation cost is recognized for financial reporting
purposes. Prior period financial statements have not been restated.
In 2003 we commenced granting a series of restricted share awards with three year vesting
periods to eligible employees. During 2006, 2005 and 2004, we contributed $7.1 million, $1.5
million and $2.1 million, respectively, under the plan through the issuance of 215,629, 75,750 and
238,750 shares, respectively, of our common stock. During 2006, 2005 and 2004, $2.1 million, $1.1
million and $0.6 million, respectively, were charged to compensation expense related to the
restricted share awards. During 2006, 2005 and 2004, we recorded credits to the contra equity
account of $0.4 million, $0.1 million and $0.2 million, respectively, for the value of 18,162,
12,832 and 28,918 shares, respectively, of non-vested restricted share awards that were forfeited
by terminated employees. The fair value of restricted stock vested during 2006, 2005, and 2004 were
$1.4 million, $0.8 million, and $0.2 million, respectively.
Total stock based compensation for the year ended December 31, 2006, of $5.7 million has
been recognized as a component of general and administrative expenses in the accompanying
Consolidated Financial Statements.
Prior to 2006, we accounted for stock-based compensation in accordance with APB 25 using
the intrinsic value method, which did not require that compensation cost be recognized for our
stock options provided the option exercise price was established at 100% of the common stock fair
market value on the date of grant. Under APB 25, we were required to record expense over the
vesting period for the value of restricted stock granted. Prior to 2006, we provided pro forma
disclosure amounts in accordance with SFAS No. 148, Accounting for Stock-Based
CompensationTransition and Disclosure (SFAS 148), as if the fair value method defined by SFAS
123 had been applied to our stock-based compensation. Our net loss and net loss per share for the
year ended December 31, 2005, would have been greater if compensation cost related to stock options
had been recorded in the financial statements based on fair value at the grant dates. Our net
income and net income per share for the year ended December 31, 2004, would have been less if
compensation cost related to stock options had been recorded in the financial statements based on
fair values at the grant dates.
Pro forma net income (loss) as if the fair value based method had been applied to all
awards for the years ended December 31, 2005 and 2004, is as follows (in thousands, except per
share amounts):
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
Net income (loss) as reported |
|
$ |
(17,450 |
) |
|
$ |
18,527 |
|
Add: Stock based compensation programs recorded as expense, net of tax |
|
|
743 |
|
|
|
579 |
|
Deduct: Total stock based compensation expense, net of tax |
|
|
(1,236 |
) |
|
|
(609 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss) |
|
$ |
(17,943 |
) |
|
$ |
18,497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common stock, as reported |
|
$ |
(18,205 |
) |
|
$ |
17,894 |
|
Add: Stock based compensation programs recorded as expense, net of tax |
|
|
743 |
|
|
|
579 |
|
Deduct: Total stock based compensation expense, net of tax |
|
|
(1,236 |
) |
|
|
(609 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss) applicable to common stock |
|
$ |
(18,698 |
) |
|
$ |
17,864 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) applicable to common stock per share: |
|
|
|
|
|
|
|
|
Basicas reported |
|
$ |
(0.78 |
) |
|
$ |
0.92 |
|
Basicpro forma |
|
$ |
(0.80 |
) |
|
$ |
0.91 |
|
Dilutedas reported |
|
$ |
(0.78 |
) |
|
$ |
0.88 |
|
Dilutedpro forma |
|
$ |
(0.80 |
) |
|
$ |
0.88 |
|
27
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The per share weighted average fair value of stock options granted during the years ended
December 31, 2006, 2005 and 2004, were $12.98, $9.69 and $7.96, respectively, on the date of grant.
The estimated fair value of the options granted during 2006 and prior years was
calculated using a Black Scholes Merton option pricing model (Black Scholes). The following
schedule reflects the various assumptions included in this model as it relates to the valuation of
our options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
December 31, |
|
December 31, |
|
|
2006 |
|
2005 |
|
2004 |
Risk free interest rate |
|
|
4.50-4.97 |
% |
|
|
4.50-6.00 |
% |
|
|
6 |
% |
Weighted average volatility |
|
|
54-57 |
% |
|
|
47-57 |
% |
|
|
46 |
% |
Dividend yield |
|
|
0 |
% |
|
|
0 |
% |
|
|
0 |
% |
Expected years until exercise |
|
|
5-6 |
|
|
|
5 |
|
|
|
5 |
|
The Black Scholes model incorporates assumptions to value stock-based awards. The
risk-free rate of interest for periods within the expected term of the option is based on a
zero-coupon U.S. government instrument over the expected term of the equity instrument. Expected
volatility is based on the historical volatility of our common stock. We generally use the midpoint
of the vesting period and the life of the grant to estimate employee option exercise timing
(expected term) within the valuation model. This methodology is not materially different from our
historical data on exercise timing. In the case of director options, we used historical exercise
behavior. Employees and directors that have different historical exercise behavior with regard to
option exercise timing and forfeiture rates are considered separately for valuation and attribution
purposes.
The following table summarizes the components of our stock-based compensation programs
recorded as expense (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
Pretax compensation expense |
|
$ |
2,092 |
|
|
$ |
1,143 |
|
|
$ |
891 |
|
Tax benefit |
|
|
(732 |
) |
|
|
(400 |
) |
|
|
(312 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock expense, net of tax |
|
$ |
1,360 |
|
|
$ |
743 |
|
|
$ |
579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director stock grants: |
|
|
|
|
|
|
|
|
|
|
|
|
Pretax compensation expense |
|
$ |
1,383 |
|
|
$ |
240 |
|
|
$ |
140 |
|
Tax benefit |
|
|
(484 |
) |
|
|
(84 |
) |
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director stock grants expense, net of tax |
|
$ |
899 |
|
|
$ |
156 |
|
|
$ |
91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
Pretax compensation expense |
|
$ |
2,487 |
|
|
$ |
|
|
|
$ |
|
|
Tax benefit |
|
|
(870 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock option expense, net of tax |
|
$ |
1,617 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total share based compensation: |
|
|
|
|
|
|
|
|
|
|
|
|
Pretax compensation expense |
|
$ |
5,962 |
|
|
$ |
1,383 |
|
|
$ |
1,031 |
|
Tax benefit |
|
|
(2,086 |
) |
|
|
(484 |
) |
|
|
(361 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total share based compensation expense,
net of tax |
|
$ |
3,876 |
|
|
$ |
899 |
|
|
$ |
670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
As of December 31, 2006, $6.6 million and $7.0 million of total unrecognized compensation
cost related to restricted stock and stock options, respectively, is expected to be recognized over
a weighted average period of approximately 1.9 years for restricted stock and 1.8 years for stock
options.
Option activity under our stock option plans as of December 31, 2006, and changes during
the 12 months then ended were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wtd. Avg. |
|
|
Remaining |
|
|
Aggregate |
|
|
|
|
|
|
|
Exercise |
|
|
Contractual |
|
|
Intrinsic |
|
|
|
Shares |
|
|
Price |
|
|
Term |
|
|
Value |
|
Outstanding at January 1, 2006 |
|
|
519,500 |
|
|
$ |
13.70 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
625,000 |
|
|
|
24.10 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(66,000 |
) |
|
|
7.24 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(55,000 |
) |
|
|
22.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
|
1,023,500 |
|
|
$ |
20.01 |
|
|
|
8.2 |
|
|
$ |
16,547,788 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2006 |
|
|
492,167 |
|
|
$ |
16.36 |
|
|
|
7.5 |
|
|
$ |
9,755,141 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value in the preceding table represents the total pre-tax
intrinsic value (the difference between our closing stock price on the last trading day of the
fourth quarter of 2006 and the exercise price, multiplied by the number of in-the-money options)
that would have been received by the option holders had all option holders exercised their options
on December 31, 2006. The amount of aggregate intrinsic value will change based on the fair market
value of our stock. The total intrinsic value of options exercised during the year ended December
31, 2006, 2005, and 2004 was $1.7 million, $0.8 million, and $0.4 million respectively.
The following table summarizes information on unvested restricted stock outstanding as of
December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
Number of |
|
|
Grant-Date |
|
|
|
Shares |
|
|
Fair Value |
|
Unvested at January 1, 2006 |
|
|
263,890 |
|
|
$ |
11.13 |
|
Vested |
|
|
(182,303 |
) |
|
|
12.03 |
|
Granted |
|
|
215,629 |
|
|
|
32.72 |
|
Forfeited |
|
|
(18,162 |
) |
|
|
21.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested at December 31, 2006 |
|
|
279,054 |
|
|
$ |
26.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In May 2006, an officer of the Company resigned and the Company accelerated the vesting
of (1) options to purchase 10,000 shares and (2) 2,916 shares of previously unvested restricted
stock that had been issued to the officer in 2004. The affected options are required to be
accounted for as a modification of an award with a service vesting condition under SFAS 123R. The
fair market value was calculated immediately prior to the modification and immediately after the
modification to determine the incremental fair market value. This incremental value and the
unamortized balance of the restricted stock resulted in the immediate recognition of compensation
expense of approximately $0.1 million.
In December of 2006, a second officer of the company resigned and the company accelerated
the vesting of 6,749 shares of previously unvested restricted stock that had been issued over the
period of 2004-2005. The unamortized balance of $0.1 million was immediately recognized as
compensation expense.
29
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
In December of 2006, the non-employee Directors of the company were granted a total of
26,824 shares of unrestricted stock to compensate them for past services. The charge in the
financial statements relative to this grant is based on the fair market value of the shares at the
grant date, and resulted in additional compensation expense of $1.1 million.
NOTE 3Asset Retirement Obligations
SFAS 143 provides accounting requirements for retirement obligations associated with
tangible long-lived assets and requires that an asset retirement cost should be capitalized as part
of the cost of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method.
The reconciliation of the beginning and ending asset retirement obligation for the
periods ending December 31, 2006 and 2005 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Beginning balance |
|
$ |
7,960 |
|
|
$ |
6,811 |
|
Liabilities incurred |
|
|
1,366 |
|
|
|
1,004 |
|
Liabilities settled |
|
|
(190 |
) |
|
|
(39 |
) |
Accretion expense |
|
|
|
|
|
|
|
|
Reflected in depreciation, depletion and
amortization |
|
|
153 |
|
|
|
70 |
|
Reflected in discontinued operations |
|
|
285 |
|
|
|
293 |
|
Other |
|
|
(17 |
) |
|
|
(179 |
) |
|
|
|
|
|
|
|
Ending balance |
|
|
9,557 |
|
|
|
7,960 |
|
Less: current portion |
|
|
(263 |
) |
|
|
(92 |
) |
|
|
|
|
|
|
|
|
|
$ |
9,294 |
|
|
$ |
7,868 |
|
|
|
|
|
|
|
|
NOTE 4Long-Term Debt
Long-term debt consisted of the following balances (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
Senior Credit Facility (see below for rate detail) |
|
$ |
26,500 |
|
|
$ |
|
|
Second-lien Term Loan, bearing interest at a weighted
average
interest rater of 8.9% at December 31, 2005 |
|
|
|
|
|
|
30,000 |
|
3.25% convertible senior notes due 2026 |
|
|
175,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
|
201,500 |
|
|
|
30,000 |
|
Less current maturities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
201,500 |
|
|
$ |
30,000 |
|
|
|
|
|
|
|
|
In December 2006, we sold $175 million of 3.25% convertible senior notes due in December,
2026. With a portion of the proceeds of the note offering we fully repaid the outstanding balance
of the second lien term loan. The notes mature on December 1, 2026, unless earlier converted,
redeemed or repurchased. The notes will be our senior unsecured obligations and will rank equally
in right of payment to all of our other existing and future indebtedness. The notes accrue interest
at a rate of 3.25% annually and paid semi-annually on June 1 and December 1 beginning June 1, 2007.
Prior to December 1, 2011, the notes will not be redeemable. On or after December 11,
2011, we may redeem for cash all or a portion of the notes, and the investors may require us to
repay the notes on each of December 11, 2011, 2016 and 2021. The notes are convertible into shares
of our common stock at a rate equal to the sum of
a) 15.1653 shares per $1,000 principal amount of notes (equal to a base conversion
price of approximately $65.94 per share) plus
b) an additional amount of shares per $1,000 of principal amount of notes equal to
the incremental share factor (2.6762), multiplied by a fraction, the numerator of which is the
applicable stock price less the base conversion price and the denominator of which is the
applicable stock price.
30
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
On November 17, 2005, we amended our existing credit agreement and entered into an amended and
restated senior credit agreement (the Senior Credit Facility) and a second lien term loan (the
Term Loan) that expanded our borrowing capabilities and extended our credit facility for an
additional two years. Total lender commitments under the Senior Credit Facility were $200.0 million
which matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are
subject to periodic redeterminations of the borrowing base which is currently established at $150.0
million, and is currently scheduled to be redetermined in March 2007, based upon our 2006 year-end
reserve report. In 2006, we fully repaid $50.0 million on the Term Loan and repaid $134.5 million
of the revolving borrowings under the Senior Credit Facility. Interest on revolving borrowings
under the Senior Credit Facility accrues at a rate calculated, at our option, at either the bank
base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base
utilization. At December 31, 2006, we had $123.5 million of excess borrowing capacity under our
revolving bank credit facility.
The terms of the Senior Credit Facility require us to maintain certain covenants.
Capitalized terms are defined in the credit agreement. The covenants include:
|
|
|
Current Ratio of 1.0/1.0, |
|
|
|
|
Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and |
|
|
|
|
Total Debt no greater than 3.5 times EBITDAX for the trailing four quarters. |
EBITDAX is earnings before interest expense, income tax, DD&A and exploration expense.
As of December 31, 2006, we were in compliance with all of the financial covenants of the
Amended and Restated Credit Agreement.
NOTE 5Net Income (Loss) Per Common Share
Net income (loss) was used as the numerator in computing basic and diluted income (loss)
per common share for the years ended December 31, 2006, 2005 and 2004. The following table
reconciles the weighted average shares outstanding used for these computations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
Basic method |
|
|
24,948 |
|
|
|
23,333 |
|
|
|
19,552 |
|
Stock warrants |
|
|
129 |
|
|
|
|
|
|
|
478 |
|
Stock options and restricted stock |
|
|
335 |
|
|
|
|
|
|
|
317 |
|
Dilutive method |
|
|
25,412 |
|
|
|
23,333 |
|
|
|
20,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 6Income Taxes
Income tax (expense) benefit consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
State |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
(904 |
) |
|
|
9,397 |
|
|
|
1,303 |
|
State |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(904 |
) |
|
|
9,397 |
|
|
|
1,303 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(904 |
) |
|
$ |
9,397 |
|
|
$ |
1,303 |
|
|
|
|
|
|
|
|
|
|
|
31
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The following is a reconciliation of the U.S. statutory income tax rate at 35% to our income
(loss) before income taxes (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Income (loss) from continuing operations |
|
|
|
|
|
|
|
|
|
|
|
|
Tax at U.S. statutory income tax |
|
$ |
(5,106 |
) |
|
$ |
13,144 |
|
|
$ |
1,262 |
|
Nondeductible expenses |
|
|
(14 |
) |
|
|
(5 |
) |
|
|
(6 |
) |
Valuation allowance and other |
|
|
|
|
|
|
5 |
|
|
|
7,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,120 |
) |
|
|
13,144 |
|
|
|
8,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
Tax at U.S. statutory income tax |
|
|
4,216 |
|
|
|
(3,747 |
) |
|
|
(7,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
4,216 |
|
|
|
(3,747 |
) |
|
|
(7,291 |
) |
|
|
|
|
|
|
|
|
|
|
Total tax (expense) benefit |
|
$ |
(904 |
) |
|
$ |
9,397 |
|
|
$ |
1,303 |
|
|
|
|
|
|
|
|
|
|
|
The tax effects of temporary differences that give rise to significant portions of the
deferred tax assets and deferred tax liabilities at December 31, 2006 and 2005 are presented below
(in thousands).
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Differences between book and tax basis of: |
|
|
|
|
|
|
|
|
Operating loss carryforwards |
|
$ |
24,599 |
|
|
$ |
16,064 |
|
Statutory depletion carryforward |
|
|
7,034 |
|
|
|
7,034 |
|
AMT tax credit carryforward |
|
|
1,480 |
|
|
|
1,480 |
|
Derivative financial instruments |
|
|
|
|
|
|
10,263 |
|
Compensation |
|
|
421 |
|
|
|
|
|
Contingent liabilities and other |
|
|
462 |
|
|
|
466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross deferred tax assets |
|
|
33,996 |
|
|
|
35,307 |
|
Less valuation allowance |
|
|
(13,263 |
) |
|
|
(13,263 |
) |
|
|
|
|
|
|
|
Net deferred tax asset |
|
|
20,733 |
|
|
|
22,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Differences between book and tax basis of: |
|
|
|
|
|
|
|
|
Property and equipment |
|
|
(6,255 |
) |
|
|
(10,464 |
) |
Derivative financial instruments |
|
|
(4,773 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gross deferred tax liabilities |
|
|
(11,028 |
) |
|
|
(10,464 |
) |
|
|
|
|
|
|
|
Net deferred tax asset |
|
$ |
9,705 |
|
|
$ |
11,580 |
|
|
|
|
|
|
|
|
Our stock based deferred compensation plans generated $3.5 million of additional tax
deductions in 2006 which are not recognized as a component of our deferred tax asset. We recognize
the benefits from excess tax stock compensation deductions after the utilization of net operating
loss carryforwards generated from operations. These excess tax benefits will be recorded as
additional paid in capital when realized. In assessing the realizability of deferred tax assets,
management considers whether it is more likely than not that some portion or all of the deferred
tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon
the generation of future taxable income during the periods in which the temporary differences
become deductible. Management considers the scheduled reversal of deferred tax liabilities,
projected future taxable income and tax planning strategies in making this assessment. Based
primarily upon the level of projections for future taxable income and the reversal of future
taxable temporary differences over the periods which the deferred tax assets are deductible,
management believes it is more likely than not we will realize the benefits of our deferred tax
assets, net of the existing valuation allowance at December 31, 2006.
32
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
We have tax net operating loss carryforwards totaling $73.8 million which expire in years 2007
through 2026 as follows (in thousands):
|
|
|
|
|
2007 |
|
$ |
7,894 |
|
2008 |
|
|
4,286 |
|
2009 |
|
|
3,247 |
|
2010 |
|
|
6,451 |
|
2011 |
|
|
|
|
2012 through 2026 |
|
|
51,907 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
73,785 |
|
|
|
|
|
|
|
|
|
|
An ownership change in accordance with Internal Revenue Code (IRC) § 382, occurred in
August 1995 and again in August 2000. The net operating losses (NOLs) generated prior to August
1995 are subject to an annual IRC § 382 limitation of $1.7 million. The IRC § 382 annual
limitation for the ownership change in August 2000 is $3.6 million. The latter IRC § 382 ownership
change limitation is a cumulative limitation and does not eliminate or increase the limitation on
the pre- August 1995 NOLs. The NOLs generated after August 1995 and prior to August 2000, are
subject to an annual limitation of $3.6 million less the annual amount utilized for pre-August 1995
NOLs. It should be noted that the same IRC § 382 limitations apply to the alternative minimum tax
net operating loss carryforwards, depletion carryforwards, and alternative minimum tax credit
carryforwards. The minimum tax credit carryforward (MTC) of $1.5 million as of December 31, 2006,
will not begin to be utilized until after the available NOLs have been utilized or expired and when
regular tax exceeds the current year alternative minimum tax. The unused annual IRC § 382
limitations can be carried over to subsequent years.
NOTE 7Stockholders Equity
Common StockAt December 31, 2006, a total of 7,733,613 unissued shares of Goodrich
common stock were reserved for the following: (a) 1,023,500 shares for the exercise of stock
options; (b) 3,587,850 shares for the conversion of Series B convertible preferred stock; and (c)
3,122,263 shares for the conversion of the 3.25% convertible senior notes. Stock warrants issued in
connection with a September 1999 private placement of convertible notes and subsidiary securities
at exercise prices ranging from $0.9375 to $1.50 per share expired in September 2006. Each warrant
was exercisable into one share of common stock upon payment of the exercise price, however, the
holders of the stock warrants could, in certain circumstances, elect a cashless exercise whereby
additional in the money warrants could be tendered to cover the exercise price of the warrants.
Pursuant to a May 2003 stock purchase agreement, the holders of 2,369,527 warrants to purchase
common stock elected a cashless exercise of such warrants resulting in the issuance of 2,109,169
shares of common stock in three separate installments which closed in January, April, and July
2004. There were no further exercises of warrants to be made pursuant to the stock purchase
agreement; however, in February 2005, the holder of 330,000 warrants to purchase common stock
elected to exercise such warrants by paying the exercise price in cash. As of December 31, 2006,
none of said warrants remained outstanding.
In May 2005, we completed a public offering of 3,710,000 shares of our common stock at an
offering price of $15.40 per share resulting in net proceeds of $53.1 million, after underwriting
discount and offering costs. We used the proceeds to repay all outstanding indebtedness to BNP
under our previous senior credit facility in the amount of $39.5 million with the balance being
added
to working capital to be used primarily to fund an accelerated drilling program in the Cotton
Valley Trend of East Texas and Northwest Louisiana.
Share Lending AgreementWith the offering of the 3.25% convertible senior notes we agreed
to lend an affiliate of Bear, Stearns & Co. (BSC) a total of 3,122,263 shares of our common stock.
The shares of stock were lent to the affiliate of BSC under the Share Lending Agreement. Under this
agreement, BSC is entitled to offer and sell such shares and use the sale to facilitate the
establishment of a hedge position by investors in the notes. BSC will receive all proceeds from all
such common stock offerings and lending transactions under this agreement. We will not receive any
of the proceeds from these transactions. BSC is obligated to return the shares to us in the event
of certain circumstances, including the redemption of the notes or the conversion of shares
pursuant to the terms of the 3.25% convertible notes offering.
33
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The 3,122,263 shares of common stock outstanding as of December 31, 2006, under the Share Lending
Agreement are required to be returned to the Company. The shares are treated in basic and diluted
earnings per share as if they were already returned and retired. There is no impact of the shares
of common stock lent under the Share Lending Agreement in the earnings per share calculation.
Preferred StockOur Series A Convertible Preferred Stock (the Series A Convertible Preferred
Stock) has a par value of $1.00 per share with a liquidation preference of $10.00 per share,
aggregating to $7.9 million,
and is convertible at the option of the holder at any time, unless earlier redeemed, into
shares of our common stock at an initial conversion rate of 0.4167 shares of common stock per share
of Series A Convertible Preferred Stock. The Series A Convertible Preferred Stock also will
automatically convert to common stock if the closing price for the Series A Convertible Preferred
Stock exceeds $15.00 per share for ten consecutive trading days. The Series A Convertible Preferred
Stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends.
Dividends on the Series A Convertible Preferred Stock accrue at an annual rate of 8% and are
cumulative. In February 2006, we fully redeemed all issued and outstanding shares of our Series A
Convertible Preferred Stock at a net cost of approximately $9.3 million.
Our Series B Convertible Preferred Stock (the Series B Convertible Preferred Stock) was
initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds
of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Convertible
Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and
bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March
15, 2006. If we fail to pay dividends on our Series B Convertible Preferred Stock on any six
dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased
by 1.0% until we have paid all dividends on our Series B Convertible Preferred Stock for all
dividend periods up to and including the dividend payment date on which the accumulated and unpaid
dividends are paid in full.
Each share is convertible at the option of the holder into our common stock, par value $0.20
per share (the Common Stock) at any time at an initial conversion rate of 1.5946 shares of Common
Stock per share, which is equivalent to an initial conversion price of approximately $31.36 per
share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock, we may choose
to deliver the conversion value to holders in cash, shares of Common Stock, or a combination of
cash and shares of Common Stock.
On or after December 21, 2010, we may, at our option, cause the Series B Convertible
Preferred Stock to be automatically converted into that number of shares of Common Stock that are
issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may
exercise our conversion right only if, for 20 trading days within any period of 30 consecutive
trading days ending on the trading day prior to the announcement of our exercise of the option, the
closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of
the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is
non-redeemable by us.
We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully
repay all outstanding indebtedness under our senior revolving credit facility. The remaining net
proceeds of the offering were added to our working capital to fund 2006 capital expenditures and
for other general corporate purposes.
On January 23, 2006, the initial purchasers of the Series B Convertible Preferred Stock
exercised their over-allotment option to purchase an additional 600,000 shares at the same price
per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital
expenditure program.
NOTE 8Hedging Activities
Commodity Hedging Activity
We enter into swap contracts, costless collars or other hedging agreements from time to
time to manage the commodity price risk for a portion of our production. We consider these to be
hedging activities and, as such, monthly settlements on these contracts are reflected in our crude
oil and natural gas sales, provided the contracts are deemed to be effective hedges under FAS
133. Our strategy, which is administered by the Hedging Committee of the Board of Directors, and
reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and
70% of our production. As of December 31, 2006, the commodity hedges we utilized were in the form
of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted
prices; and (b) collars, where we receive the excess, if any, of the floor price over the reference
price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the
ceiling price. Hedge ineffectiveness results from difference changes in the NYMEX contract terms
and the physical location, grade and quality of our oil and gas production. As of December 31,
2006, our open forward positions on our outstanding commodity hedging contracts, all of which were
with either BNP or Bank of Montreal (BMO), was as follows:
34
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
Swaps |
|
Volume |
|
Price |
Natural gas (MMBtu/day) |
|
|
|
|
|
|
|
|
1Q 2007 |
|
|
10,000 |
|
|
$ |
7.77 |
|
Oil (Bbl/day) |
|
|
|
|
|
|
|
|
1Q 2007 |
|
|
400 |
|
|
$ |
53.35 |
|
2Q 2007 |
|
|
400 |
|
|
|
53.35 |
|
3Q 2007 |
|
|
400 |
|
|
|
53.35 |
|
4Q 2007 |
|
|
400 |
|
|
|
53.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars |
|
Volume |
|
Floor/Cap |
Natural gas (MMBtu/day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q 2007 |
|
|
10,000 |
|
|
$ |
9.00 |
|
|
|
$ |
10.65 |
|
2Q 2007 |
|
|
10,000 |
|
|
|
9.00 |
|
|
|
$ |
10.65 |
|
3Q 2007 |
|
|
10,000 |
|
|
|
9.00 |
|
|
|
$ |
10.65 |
|
4Q 2007 |
|
|
10,000 |
|
|
|
9.00 |
|
|
|
$ |
10.65 |
|
1Q 2007 |
|
|
15,000 |
|
|
$ |
7.00 |
|
|
|
$ |
13.60 |
|
2Q 2007 |
|
|
15,000 |
|
|
|
7.00 |
|
|
|
$ |
13.60 |
|
3Q 2007 |
|
|
15,000 |
|
|
|
7.00 |
|
|
|
$ |
13.60 |
|
4Q 2007 |
|
|
15,000 |
|
|
|
7.00 |
|
|
|
$ |
13.60 |
|
2Q 2007 |
|
|
5,000 |
|
|
$ |
7.00 |
|
|
|
$ |
13.90 |
|
3Q 2007 |
|
|
5,000 |
|
|
|
7.00 |
|
|
|
$ |
13.90 |
|
4Q 2007 |
|
|
5,000 |
|
|
|
7.00 |
|
|
|
$ |
13.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl/day) |
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q 2007 |
|
|
400 |
|
|
$ |
60.00 |
|
|
|
$ |
76.50 |
|
2Q 2007 |
|
|
400 |
|
|
$ |
60.00 |
|
|
|
$ |
76.50 |
|
3Q 2007 |
|
|
400 |
|
|
$ |
60.00 |
|
|
|
$ |
76.50 |
|
4Q 2007 |
|
|
400 |
|
|
$ |
60.00 |
|
|
|
$ |
76.50 |
|
The fair value of the oil and gas hedging contracts in place at December 31, 2006,
resulted in a net asset of $13.4 million. As of December 31, 2006, $1.2 million (net of $0.6
million in income taxes) of deferred losses on derivative instruments accumulated in other
comprehensive loss are expected to be reclassified into earnings during the next twelve months. For
the year ended December 31, 2006, we recognized in earnings a gain from derivatives not qualifying
for hedge accounting in the amount of $38.1 million (also included in this gain amount are
settlement payments on ineffective gas and oil hedges totaling $2.1 million in 2006). This gain was
recognized because our gas hedges were deemed to be ineffective for 2006, and all of our oil hedges
were deemed ineffective in the fourth quarter of 2006, accordingly, the changes in fair value of
such hedges could no longer be reflected in other comprehensive loss. In the fourth quarter of
2006, we reclassified $0.7 million of previously deferred losses (net of $0.4 million
in
income taxes) from accumulated other comprehensive loss to loss on derivatives not qualifying
for hedge accounting as the cash flow of the hedged items was recognized.
For the year ended December 31, 2006, we realized effective oil hedge losses of $3.5 million
all related to our South Louisiana properties which are recognized in Discontinued Operations on
the Consolidated Statements of Operations. See Note 12 Acquisitions and Divestitures to our
consolidated financial statements for a further discussion of our discontinued operations.
Subsequent to year end, we unwound the oil collar for 400 barrels per day referenced
above. As a result, we expect to recognize a gain of $0.9 million in the first quarter of 2007.
Subsequent to year end, we have entered into a series of physical sales contracts which will result
in us selling approximately 18,500 MMbtu of gas per day in calendar year 2008 for an average price
of $8.01 MMbtu before transportation charges.
Despite the measures taken by us to attempt to control price risk, we remain subject to price
fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas
sold on the spot market are volatile due primarily to seasonality of demand and other factors
beyond our control. Domestic crude oil and gas prices could have a material adverse effect on our
financial position, results of operations and quantities of reserves recoverable on an economic
basis.
35
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Interest Rate Swaps
We have a variable-rate debt obligation that exposes us to the effects of changes in
interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter
into interest rate swap agreements. At December 31, 2006, we had the following interest rate swaps
in place with BNP (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective |
|
|
|
Maturity |
|
LIBOR |
|
Notional |
Date |
|
|
|
Date |
|
Swap Rate |
|
Amount |
|
02/27/06 |
|
|
|
|
|
02/26/07 |
|
|
|
4.08 |
% |
|
|
23.0 |
|
|
02/27/06 |
|
|
|
|
|
02/26/07 |
|
|
|
4.85 |
% |
|
|
17.0 |
|
|
02/27/07 |
|
|
|
|
|
02/26/09 |
|
|
|
4.86 |
% |
|
|
40.0 |
|
The fair value of the interest rate swap contracts in place at December 31, 2006,
resulted in an asset of $0.2 million. For the years ended December 31, 2006 and 2005, our earnings
were not significantly affected by cash flow hedging ineffectiveness of the interest rates swaps.
NOTE 9Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in
accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial
Instruments (SFAS 107). The estimated fair value amounts have been determined using available
market information and valuation methodologies described below. Considerable judgment is required
in interpreting market data to develop the estimates of fair value. The use of different market
assumptions or valuation methodologies may have a material effect on the estimated fair value
amounts.
The carrying values of items comprising current assets and current liabilities approximate
fair values due to the short-term maturities of these instruments. The carrying amounts and fair
values of the other financial instruments and derivatives at December 31, 2006 and 2005, are as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
Carrying |
|
|
|
|
|
Carrying |
|
|
|
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
Second Lien Term Loan |
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
30,000 |
|
|
$ |
30,000 |
|
Senior Credit Facility |
|
|
26,500 |
|
|
|
26,500 |
|
|
|
|
|
|
|
|
|
3.25% Convertible Senior Notes |
|
|
175,000 |
|
|
|
170,240 |
|
|
|
|
|
|
|
|
|
Derivative assets (liabilities) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
(1,446 |
) |
|
|
(1,446 |
) |
|
|
(4,810 |
) |
|
|
(4,810 |
) |
Gas |
|
|
14,865 |
|
|
|
14,865 |
|
|
|
(24,620 |
) |
|
|
(24,620 |
) |
Interest rate |
|
|
219 |
|
|
|
219 |
|
|
|
107 |
|
|
|
107 |
|
NOTE 10Commitments and Contingencies
Operating LeasesWe have commitments under an operating lease agreement for office space.
Total rent expense for the years ended December 31, 2006, 2005, and 2004, was approximately $0.6
million, $0.4 million, and $0.3 million respectively. We also have non-cancellable drilling rig
commitments with various term end dates through 2009.
Transportation ContractsWe have entered into two gas gathering and processing agreements
where we are obligated to pay a minimum amount, as calculated on a yearly amount, or pay
deficiencies at a specified gathering fee rate. Our production committed to these contracts is
expected to exceed the minimum yearly volumes provided in the contracts, therefore avoiding
payments for deficiencies.
36
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
In 2007 we purchased acreage that was committed to a gas gathering agreement where we have a
four year obligation to pay a minimum amount, as calculated on a yearly amount, or pay deficiencies
at a specified gathering fee rate. The first year of the contract commitment began on September 1,
2006. Our potential share of the minimum yearly amount ranges from approximately $0.1 million in
the first year to approximately $0.5 million in the fourth year. The potential effect of this
agreement is not included in the table below since our share of the commitment will not be
determined until well(s) are drilled in 2007.
At December 31, 2006, future minimum rental payments due, drilling rig commitments, and
transportation contract commitments are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by Period |
|
|
|
|
|
|
|
|
|
|
After |
|
|
|
Total |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2011 |
|
Operating lease for office space |
|
$ |
1,992 |
|
|
$ |
701 |
|
|
$ |
710 |
|
|
$ |
491 |
|
|
$ |
48 |
|
|
$ |
42 |
|
|
$ |
|
|
Drilling rig commitments |
|
|
80,247 |
|
|
|
45,983 |
|
|
|
24,956 |
|
|
|
9,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation contracts |
|
|
2,159 |
|
|
|
758 |
|
|
|
540 |
|
|
|
540 |
|
|
|
321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (1) |
|
$ |
84,398 |
|
|
$ |
47,442 |
|
|
$ |
26,206 |
|
|
$ |
10,339 |
|
|
$ |
369 |
|
|
$ |
42 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This table does not include the estimated liability for dismantlement,
abandonment and restoration costs of oil and gas properties of $9.6
million. The Company records a separate liability for the fair value of
this asset retirement obligation. See Note 3. |
ContingenciesIn July 2005, we received a Notice of Proposed Tax Due from the State of
Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004
in the amount of $0.5 million. The Notice of Proposed Tax Due includes additional assessments of
penalties and interest in the amount of $0.4 million for a total asserted liability of $0.9
million. We believe that we have fully paid our Louisiana franchise taxes for the years in
question; therefore, we intend to vigorously contest the Notice of Proposed Tax Due. We have
commenced our analysis of this contingency and have not recorded any provision for possible payment
of additional Louisiana franchise taxes nor any related penalties and interest.
LitigationIn the third quarter of 2004, we recognized a non-recurring gain in the amount
of $2.1 million, reflecting the proceeds of a successful litigation judgment. We commenced the
litigation as plaintiff in February 2000 against the operator of a South Louisiana property which
was jointly acquired by us and the defendant in September 1999. The judgment provided for recovery
of our damages and a portion of our attorneys fees as well as interest calculated on our damages.
We are party to additional lawsuits arising in the normal course of business. We intend to defend
these actions vigorously and believe, based on currently available information, that adverse
results or judgments from such actions, if any, will not be material to our financial position or
results of operations.
NOTE 11Related Party Transactions
On March 12, 2002, we completed the sale of a 30% working interest in the existing
production and shallow rights, and a 15% working interest in the deep rights below 10,600 feet, in
our Burrwood and West Delta 83 fields for $12.0 million to Malloy Energy
Company, LLC (MEC), led by Patrick E. Malloy, III and participated in by Sheldon Appel, each
of whom were members of our Board of Directors at that time, as well as Josiah Austin, who
subsequently became a member of our Board of Directors. Mr. Malloy is now Chairman of our Board of
Directors and Mr. Appel retired from the Board of Directors in February 2004.
Subsequent to the acquisition of a 30% working interest in the Burrwood and West Delta 83
fields in March 2002, MEC acquired an approximate 30% working interest in three other fields we
operated in 2003 and 2004. In accordance with industry standard joint operating agreements, we bill
MEC for its share of the capital and operating costs of the three fields on a monthly basis. As of
December 31, 2006 and 2005, the amounts billed and outstanding to MEC for its share of monthly
capital and operating costs were $1.3 million and $0.5 million, respectively, and are included in
trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by
MEC to us in the month subsequent to billing and the affiliate is current on payment of its
billings.
We also serve as the operator for a number of other oil and gas wells owned by an
affiliate of MEC in which we own a 7% after payout working interest. In accordance with industry
standard joint operating agreements, we bill the affiliate for its share of the capital and
operating costs of these wells on a monthly basis. As of December 31, 2006 and 2005, the amounts
billed and outstanding to the affiliate for its share of monthly capital and operating costs were
$19,000 and $78,000, respectively, and are included in trade and other accounts receivable at each
year-end. Such amounts at each year-end were paid by the affiliate to us in the month subsequent to
billing and the affiliate is current on payment of its billings.
37
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Additionally, we also serve as the operator for a number of other oil and gas wells owned by
an affiliate of MEC whereby we do not have a working interest. In accordance with industry standard
joint operating agreements, we bill the affiliate for its share of the capital and operating costs
of these wells on a monthly basis. As of December 31, 2006 and 2005, the amounts billed and
outstanding to the affiliate for its share of monthly capital and operating costs were $81,000 and
$272,000, respectively, and are included in trade and other accounts receivable at each year-end.
Such amounts at each year-end were paid by the affiliate to us in the month subsequent to billing
and the affiliate is current on payment of its billings.
NOTE 12Acquisitions and Divestitures
On February 7, 2007, we announced the acquisition of drilling and development rights to
acreage located in the Angelina River play. We acquired a 60% working interest in the acreage and
will operate the joint venture. The acquisition was completed in two separate transactions. In the
initial transaction, we acquired a 40% working interest for $2.0 million from a private company. We
also agreed to carry the private company for a 20% working interest in the drilling of five wells.
In the second transaction, we are purchasing the remaining 20% working interest in the acreage in a
like-kind exchange for our 30% interest in the Mary Blevins field.
On December 6, 2006, we closed on the acquisition of additional interests in the
Dirgin-Beckville field in the Cotton Valley Trend for $6.1 million from a private company. With
this acquisition, we now own an approximate 99% working interest in this field.
Discontinued Operations
On January 12, 2007, the Company and Malloy Energy entered into a Purchase and Sale Agreement
with a private company for the sale of substantially all of the Companys oil and gas properties in
South Louisiana. The total sales price for the companys interest in the oil and gas properties was
approximately $100 million, effective July 1, 2006. The total sales price for Malloy Energys
interests in these properties was approximately $30 million with the same effective date. See Note
11 Related Party Transactions for additional information regarding Malloy Energy. Both the
Company and Malloy Energys total consideration was reduced by an amount equal to its proportionate
share of the greater of $20 million or normal closing adjustments. The adjusted sales price for the
Companys interest was $77 million. The effective date of the transaction was July 1, 2006 and the
closing date of the sale was late March, 2007. Subsequent to December 31, 2006, the companys
interest in oil and gas properties in South Louisiana met the criteria for reporting as held for
sale. The company completed the sale in the first quarter of 2007. Mr. Malloy is Chairman
of our Board of Directors. The carrying value of the assets and
liabilities disposed of was $62 million consisting of
$131 million in property, plant and equipment, less
$63 million in accumulated depreciation, depletion and
amortization and $6 million in asset retirement obligation
liabilities.
In October 2004, we sold our operated interests in the Marholl and Sean Andrew fields, along
with our non-operated interests in the Ackerly field, all of which were located in West Texas, for
gross proceeds of approximately $2.1 million. We realized a gain of $0.9 million on the sale of
these non-core properties.
In accordance with SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived
Assets, the results of operations and gain relating to these divested properties and for the
properties held for sale have been reflected as discontinued
operations. Note 6 Income Taxes has been revised as a
result of discontinued operations.
Results for these properties reported as discontinued operations were as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended |
|
|
December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
|
(in thousands) |
Revenues |
|
$ |
41,383 |
|
|
$ |
34,092 |
|
|
$ |
41,668 |
|
Income (loss) from discontinued operations |
|
|
(11,876 |
) |
|
|
10,707 |
|
|
|
20,830 |
|
Income tax benefit (expense) |
|
|
4,216 |
|
|
|
(3,747 |
) |
|
|
(7,291 |
) |
Income (loss) from discontinued operations net
of tax |
|
|
(7,660 |
) |
|
|
6,960 |
|
|
|
13,539 |
|
38
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
NOTE 13Oil and Gas Producing Activities (Unaudited)
Capitalized Costs Related to Oil and Gas Producing Activities
The table below reflects our capitalized costs related to oil and gas producing
activities at December 31, 2006, and 2005 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Proved properties |
|
$ |
555,013 |
|
|
$ |
301,842 |
|
Unproved properties |
|
|
20,653 |
|
|
|
14,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
575,666 |
|
|
|
316,286 |
|
Less accumulated depreciation, depletion and amortization |
|
|
(155,204 |
) |
|
|
(73,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties |
|
$ |
420,462 |
|
|
$ |
242,995 |
|
Costs Incurred
Costs incurred in oil and gas property acquisition, exploration and development
activities, whether capitalized or expensed, are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Property
Acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
$ |
8,569 |
|
|
$ |
9,216 |
|
|
$ |
5,528 |
|
Proved |
|
|
6,120 |
|
|
|
|
|
|
|
|
|
Exploration |
|
|
12,263 |
|
|
|
14,021 |
|
|
|
4,874 |
|
Development (1) |
|
|
244,240 |
|
|
|
143,574 |
|
|
|
36,351 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
271,192 |
|
|
$ |
166,811 |
|
|
$ |
46,753 |
|
|
|
|
(1) |
|
Includes asset retirement costs of $1.3 million in 2006, $1.1 million in 2005 and $0.4 million in 2004. |
Oil and Natural Gas Reserves
All of our reserve information related to crude oil, condensate, and natural gas liquids
and natural gas was compiled based on evaluations performed by Netherland, Sewell & Associates,
Inc. as of December 31, 2006 and 2005. All of the subject reserves are located in the continental
United States.
Many assumptions and judgmental decisions are required to estimate reserves. Quantities
reported are considered reasonable but are subject to future revisions, some of which may be
substantial, as additional information becomes available. Such additional knowledge may be gained
as the result of reservoir performance, new geological and geophysical data, additional drilling,
technological advancements, price changes, and other factors.
Regulations published by the SEC define proved reserves as those volumes of crude oil,
condensate, and natural gas liquids and natural gas that geological and engineering data
demonstrate with reasonable certainty are recoverable from known reservoirs under
existing economic and operating conditions. Proved developed reserves are those volumes expected to
be recovered through existing wells with existing equipment and operating methods. Proved
undeveloped reserves are those volumes expected to be recovered as a result of making additional
investments by drilling new wells on acreage offsetting productive units or recompleting existing
wells.
39
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The following table sets forth our net proved oil and gas reserves at December 31, 2006, 2005
and 2004 and the changes in net proved oil and gas reserves for the years ended December 31, 2006,
2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf) |
|
Oil (MBbls) |
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
Proved Reserves at
beginning of period |
|
|
142,963 |
|
|
|
67,682 |
|
|
|
30,903 |
|
|
|
4,973 |
|
|
|
5,589 |
|
|
|
7,805 |
|
Revisions of previous
estimates (1) |
|
|
(66,409 |
) |
|
|
(10,382 |
) |
|
|
(6,666 |
) |
|
|
(1,612 |
) |
|
|
(648 |
) |
|
|
(3,466 |
) |
Extensions, discoveries and
other additions (2) |
|
|
115,732 |
|
|
|
91,900 |
|
|
|
48,322 |
|
|
|
311 |
|
|
|
440 |
|
|
|
1,987 |
|
Purchases of minerals in place |
|
|
7,727 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
Sales of minerals in place |
|
|
|
|
|
|
|
|
|
|
(54 |
) |
|
|
|
|
|
|
|
|
|
|
(249 |
) |
Production |
|
|
(13,001 |
) |
|
|
(6,237 |
) |
|
|
(4,823 |
) |
|
|
(474 |
) |
|
|
(408 |
) |
|
|
(488 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves at end
of period |
|
|
187,012 |
|
|
|
142,963 |
|
|
|
67,682 |
|
|
|
3,201 |
|
|
|
4,973 |
|
|
|
5,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf) |
|
|
Oil (MBbls) |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Proved developed: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
56,700 |
|
|
|
24,362 |
|
|
|
23,429 |
|
|
|
1,796 |
|
|
|
2,228 |
|
|
|
3,601 |
|
End of period |
|
|
76,679 |
|
|
|
56,700 |
|
|
|
24,362 |
|
|
|
1,862 |
|
|
|
1,796 |
|
|
|
2,228 |
|
|
|
|
(1) |
|
Revisions of previous estimates were negative on an overall basis in 2006,
2005 and 2004 related to the following: (a) with respect to 2006, the
primary cause of the revisions was the significant pricing difference
between December 31, 2006 and December 31, 2005, which caused a number of
our proved undeveloped locations in the Cotton Valley area to become
uneconomic at the lower prices, as well as some volume revisions in these
same properties and in South Louisiana as a result of updated production
performance, and (b) with respect to 2005 and 2004, the premature
depletion or decline in production from our South Louisiana wells which
had larger estimates of producible reserves at the previous reporting
period and new and/or revised interpretations of technical data from
recently drilled wells in that region, updated production performance from
existing and offset wells, and/or the results of enhanced 3-D seismic
evaluations. |
|
(2) |
|
Extensions, discoveries and other reserve additions were positive on an
overall basis in 2006, primarily related to our continued drilling
activities on existing and newly acquired properties in the Cotton Valley
Trend of East Texas and North Louisiana. The main reason for the increases
in 2005 and 2004 was the commencement of our Cotton Valley drilling
program in the first quarter of 2004 which resulted in a substantial
volume of both proved developed and proved undeveloped reserves being
recorded in those years. |
40
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The following table summarizes our combined oil and gas reserve information on an MMcfe
basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
Total proved |
|
|
206,217 |
|
|
|
172,799 |
|
|
|
101,216 |
|
Proved developed |
|
|
87,852 |
|
|
|
67,474 |
|
|
|
37,732 |
|
Standardized Measure
The standardized measure of discounted future net cash flows relating to proved oil and
natural gas reserves as of year-end is shown below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Future revenues |
|
$ |
1,190,367 |
|
|
$ |
1,798,972 |
|
|
$ |
654,543 |
|
Future lease operating expenses and production taxes |
|
|
(409,775 |
) |
|
|
(379,872 |
) |
|
|
(151,186 |
) |
Future development costs (1) |
|
|
(337,576 |
) |
|
|
(245,868 |
) |
|
|
(86,919 |
) |
Future income tax expense |
|
|
(28,764 |
) |
|
|
(353,472 |
) |
|
|
(104,870 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
414,252 |
|
|
|
819,760 |
|
|
|
311,568 |
|
10% annual discount for estimated timing of cash flows |
|
|
(213,971 |
) |
|
|
(409,140 |
) |
|
|
(130,890 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net
cash flows |
|
$ |
200,281 |
|
|
$ |
410,620 |
|
|
$ |
180,678 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price used to calculate reserves (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
5.64 |
|
|
$ |
10.54 |
|
|
$ |
6.14 |
|
Oil (per Bbl) |
|
$ |
57.75 |
|
|
$ |
58.80 |
|
|
$ |
42.72 |
|
|
|
|
(1) |
|
Includes cumulative asset retirement obligations of $9.6 million, $8.0
million and $6.8 million in 2006, 2005 and 2004, respectively. |
|
(2) |
|
These average prices, used to estimate our reserves at these dates,
reflect applicable transportation and quality differentials on a
well-by-well basis. |
Future revenues are computed by applying year-end prices of oil and gas to the year-end
estimated future production of proved oil and gas reserves. The base prices used for the PV-10
calculation were public market prices on December 31 adjusted by differentials to those market
prices. These price adjustments were done on a property-by-property basis for the quality of the
oil and natural gas and for transportation to the appropriate location. Estimates of future
development and production costs are based on year-end costs and assume continuation of existing
economic conditions and year-end prices. We will incur significant capital in the development of
our Cotton Valley Trend properties. We believe with reasonable certainty that we will be able to
obtain such capital in the normal course of business. The estimated future net cash flows are then
discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash
flows. The standardized measure of discounted cash flows is the future net cash flows less the
computed discount.
41
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Changes in Standardized Measure
The following are the principal sources of change in the standardized measure of
discounted net cash flows for the years shown (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Net changes in prices and production costs
related to future production |
|
$ |
(360,635 |
) |
|
$ |
185,709 |
|
|
$ |
84,156 |
|
Sales and transfers of oil and gas produced, net
of production costs |
|
|
(81,813 |
) |
|
|
(53,845 |
) |
|
|
(34,354 |
) |
Net change due to revisions in quantity estimates |
|
|
(70,212 |
) |
|
|
(48,540 |
) |
|
|
(27,462 |
) |
Net change due to extensions, discoveries and
improved recovery |
|
|
122,144 |
|
|
|
321,529 |
|
|
|
60,239 |
|
Net change due to purchases and sales of
minerals in place |
|
|
8,044 |
|
|
|
|
|
|
|
(4,278 |
) |
Future development costs |
|
|
(44,339 |
) |
|
|
(79,618 |
) |
|
|
(53,739 |
) |
Net change in income taxes |
|
|
142,131 |
|
|
|
(124,526 |
) |
|
|
(22,640 |
) |
Accretion of discount |
|
|
58,768 |
|
|
|
24,148 |
|
|
|
21,462 |
|
Change in production rates (timing) and other |
|
|
15,573 |
|
|
|
5,085 |
|
|
|
(6,680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(210,339 |
) |
|
$ |
229,942 |
|
|
$ |
16,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 14Summarized Quarterly Financial Data (Unaudited)
(In Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
14,769 |
|
|
$ |
20,154 |
|
|
$ |
19,624 |
|
|
$ |
20,224 |
|
|
$ |
74,771 |
|
Operating income (loss) |
|
|
577 |
|
|
|
(248 |
) |
|
|
(2,166 |
) |
|
|
(13,415 |
) |
|
|
(15,252 |
)(2) |
Income (loss) from continuing operations |
|
|
8,726 |
|
|
|
2,719 |
|
|
|
6,844 |
|
|
|
(8,990 |
) |
|
|
9,299 |
|
Income (loss) from discontinued operations,
net of tax |
|
|
2,866 |
|
|
|
1,579 |
|
|
|
1,337 |
|
|
|
(13,442 |
) |
|
|
(7,660 |
) |
Net income (loss) |
|
|
11,592 |
|
|
|
4,298 |
|
|
|
8,181 |
|
|
|
(22,432 |
) |
|
|
1,639 |
(2) |
Net income (loss) applicable to common stock |
|
|
8,575 |
|
|
|
2,777 |
|
|
|
6,670 |
|
|
|
(23,944 |
) |
|
|
(5,922 |
) |
Basic income (loss) per average common share (1) |
|
|
0.47 |
|
|
|
0.17 |
|
|
|
0.33 |
|
|
|
(0.90 |
) |
|
|
0.07 |
|
Diluted income (loss) per average common share (1) |
|
|
0.46 |
|
|
|
0.17 |
|
|
|
0.32 |
|
|
|
(0.90 |
) |
|
|
0.06 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
3,435 |
|
|
$ |
4,796 |
|
|
$ |
8,811 |
|
|
$ |
18,269 |
|
|
$ |
35,311 |
|
Operating income (loss) |
|
|
(2,388 |
) |
|
|
(2,348 |
) |
|
|
38 |
|
|
|
7,183 |
|
|
|
2,485 |
|
Income (loss) from continuing operations |
|
|
(8,152 |
) |
|
|
(2,039 |
) |
|
|
(21,425 |
) |
|
|
7,206 |
|
|
|
(24,410 |
) |
Income from discontinued operations, net of tax |
|
|
2,001 |
|
|
|
1,594 |
|
|
|
1,951 |
|
|
|
1,414 |
|
|
|
6,960 |
|
Net income (loss) |
|
|
(6,151 |
) |
|
|
(445 |
) |
|
|
(19,474 |
) |
|
|
8,620 |
|
|
|
(17,450 |
)(3) |
Net income (loss) applicable to common stock |
|
|
(6,309 |
) |
|
|
(603 |
) |
|
|
(19,632 |
) |
|
|
8,339 |
|
|
|
(18,205 |
)(3) |
Basic income (loss) per average common share (1) |
|
|
(0.30 |
) |
|
|
(0.02 |
) |
|
|
(0.79 |
) |
|
|
0.35 |
|
|
|
(0.75 |
) |
Diluted income (loss) per average common share (1) |
|
|
(0.30 |
) |
|
|
(0.02 |
) |
|
|
(0.79 |
) |
|
|
0.34 |
|
|
|
(0.75 |
) |
|
|
|
(1) |
|
The sum of the per share amounts per quarter does not equal the year due to the changes in
the average number of common shares outstanding. |
|
(2) |
|
Includes a $40.2 million unrealized gain on derivatives not qualifying for hedge accounting. |
|
(3) |
|
Includes a $27.0 million unrealized loss on derivatives not qualifying for hedge accounting. |
42
ITEM 9.01. FINANCIAL STATEMENTS AND EXHIBITS
(d) Exhibits:
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
12.1
|
|
Ratio of Earnings to Fixed Charges |
|
|
|
12.2
|
|
Ratio of Earnings to Fixed Charges
and Preference Securities Dividends |
|
|
|
23.1
|
|
Consent of KPMG LLP |
|
|
|
23.2
|
|
Consent of Netherland, Sewell & Associates, Inc. |
43
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the
Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly
authorized.
|
|
|
|
|
|
|
|
|
GOODRICH PETROLEUM CORPORATION |
|
|
|
|
(Registrant) |
|
|
|
|
|
|
|
|
|
|
|
/s/
|
|
David R. Looney |
|
|
|
|
|
|
|
|
|
|
|
David R. Looney |
|
|
|
|
|
|
Executive Vice President & Chief Financial Officer |
|
|
Dated:
August 7, 2007
44
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
12.1
|
|
Ratio of Earnings to Fixed Charges |
|
|
|
12.2
|
|
Ratio of Earnings to Fixed Charges
and Preference Securities Dividends |
|
|
|
23.1
|
|
Consent of KPMG LLP |
|
|
|
23.2
|
|
Consent of Netherland, Sewell & Associates, Inc. |
45